Table of Contents


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 20172018
or
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission
File Number
 Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number IRS Employer Identification Number
     
1-16169 EXELON CORPORATION 23-2990190
  
(a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago, Illinois 60680-5379
(800) 483-3220
  
     
333-85496 EXELON GENERATION COMPANY, LLC 23-3064219
  
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348-2473
(610) 765-5959
  
     
1-1839 COMMONWEALTH EDISON COMPANY 36-0938600
  
(an Illinois corporation)
440 South LaSalle Street
Chicago, Illinois 60605-1028
(312) 394-4321
  
     
000-16844 PECO ENERGY COMPANY 23-0970240
  
(a Pennsylvania corporation)
P.O. Box 8699
2301 Market Street
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000
  
     
1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
  
(a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore, Maryland 21201-3708
(410) 234-5000
  
     
001-31403 PEPCO HOLDINGS LLC 52-2297449
  
(a Delaware limited liability company)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000

  
     
001-01072 POTOMAC ELECTRIC POWER COMPANY 53-0127880
  
(a District of Columbia and Virginia corporation)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000

  
     
001-01405 DELMARVA POWER & LIGHT COMPANY 51-0084283
  
(a Delaware and Virginia corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000

  
     
001-03559 ATLANTIC CITY ELECTRIC COMPANY 21-0398280
  
(a New Jersey corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000

  

Table of Contents



Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  x  No  o
Indicate by check mark whether the registrant has submitted electronically 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  x  No  o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

 Large Accelerated Filer Accelerated Filer Non-accelerated Filer Smaller Reporting Company Emerging Growth Company
Exelon Corporationx



    
Exelon Generation Company, LLC



x    
Commonwealth Edison Company



x    
PECO Energy Company



x    
Baltimore Gas and Electric Company



x    
Pepco Holdings LLC    x    
Potomac Electric Power Company    x    
Delmarva Power & Light Company    x    
Atlantic City Electric Company    x    
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  o  No  x
The number of shares outstanding of each registrant’s common stock as of September 30, 20172018 was:
Exelon Corporation Common Stock, without par value960,852,473967,009,746
Exelon Generation Company, LLCnot applicable
Commonwealth Edison Company Common Stock, $12.50 par value127,021,214127,021,324
PECO Energy Company Common Stock, without par value170,478,507
Baltimore Gas and Electric Company Common Stock, without par value1,000
Pepco Holdings LLCnot applicable
Potomac Electric Power Company Common Stock, $.01$0.01 par value100
Delmarva Power & Light Company Common Stock, $2.25 par value1,000
Atlantic City Electric Company Common Stock, $3.00 par value8,546,017



Table of Contents


TABLE OF CONTENTS

 Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS
64
FILING FORMAT
9
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
9
WHERE TO FIND MORE INFORMATION
9
PART I.
FINANCIAL INFORMATION
10
ITEM 1.
FINANCIAL STATEMENTS
10
Exelon Corporation
Consolidated Statements of Operations and Comprehensive Income
11
Consolidated Statements of Cash Flows
12
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
12Consolidated Balance Sheets
WHERE TO FIND MORE INFORMATION
12
PART I.FINANCIAL INFORMATION
13
ITEM 1.FINANCIAL STATEMENTS
13
 Exelon Corporation
Consolidated StatementsStatement of Operations and Comprehensive Income
14Changes in Shareholders’ Equity
Consolidated Statements of Cash Flows
15
 
Exelon Generation Company, LLC
Consolidated Balance SheetsStatements of Operations and Comprehensive Income
16
 
Consolidated StatementStatements of Changes in Shareholders’ EquityCash Flows
17
Consolidated Balance Sheets
18
 Exelon Generation Company, LLC
Consolidated StatementsStatement of Operations and Comprehensive Income
19Changes in Equity
Consolidated Statements of Cash Flows
20
 
Commonwealth Edison Company
Consolidated Balance SheetsStatements of Operations and Comprehensive Income
21
 
Consolidated StatementStatements of Changes in EquityCash Flows
22
Consolidated Balance Sheets
23
 Commonwealth Edison Company
Consolidated StatementsStatement of Operations and Comprehensive Income
24Changes in Shareholders' Equity
Consolidated Statements of Cash Flows
25
 
PECO Energy Company
Consolidated Balance SheetsStatements of Operations and Comprehensive Income
26
 
Consolidated StatementStatements of Changes in Shareholders' EquityCash Flows
27
Consolidated Balance Sheets
28
 PECO Energy Company
Consolidated StatementsStatement of Operations and Comprehensive Income
29Changes in Shareholder's Equity
Consolidated Statements of Cash Flows
30
 
Baltimore Gas and Electric Company
Consolidated Balance SheetsStatements of Operations and Comprehensive Income
31
 
Consolidated StatementStatements of Changes in Shareholder's EquityCash Flows
32
Consolidated Balance Sheets
33
 Baltimore Gas and Electric Company
Consolidated StatementsStatement of Operations and Comprehensive Income
34Changes in Shareholders’ Equity
Consolidated Statements of Cash Flows
35
 
Pepco Holdings LLC
Consolidated Balance SheetsStatements of Operations and Comprehensive Income
36
 
Consolidated StatementStatements of Changes in Shareholders’ EquityCash Flows
37
Consolidated Balance Sheets
38
 Pepco Holdings LLC
Consolidated Statements of Operations and Comprehensive Income
39
Consolidated Statements of Cash Flows
40
Consolidated Balance Sheets
41
Consolidated Statement of Changes in Equity
4340

3
Table of Contents


 Page No.
 
Potomac Electric Power Company
 
 
Statements of Operations and Comprehensive Income
4441
 
Statements of Cash Flows
42
Balance Sheets
43
Statement of Changes in Shareholder's Equity
45
 Balance Sheets
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
46
 Statement
Statements of Changes in Shareholder's EquityCash Flows
47
Balance Sheets
48
 Delmarva Power & Light Company
Statements
Statement of Operations and Comprehensive Income
49Changes in Shareholder’s Equity
Statements of Cash Flows
50
 Balance Sheets
Atlantic City Electric Company
Consolidated Statements of Operations and Comprehensive Income
51
 Statement
Consolidated Statements of Changes in Shareholder’s EquityCash Flows
52
Consolidated Balance Sheets
53
 Atlantic City Electric Company
Consolidated StatementsStatement of Operations and Comprehensive Income
54Changes in Shareholder’s Equity
Consolidated Statements of Cash Flows
55
 
Combined Notes to Consolidated Balance SheetsFinancial Statements
56
 Consolidated Statement of Changes in Shareholder’s Equity
1. Significant Accounting Policies
5857
 Combined Notes to Consolidated Financial Statements
2. New Accounting Standards
5962
 1. Basis of Presentation
3. Variable Interest Entities
5964
 2. New Accounting Standards
4. Mergers, Acquisitions and Dispositions
6069
 3. Variable Interest Entities
5. Revenue from Contracts with Customers
6372
 4. Mergers, Acquisitions and Dispositions
6. Regulatory Matters
7076
 5. Regulatory Matters
78
6.7. Impairment of Long-Lived Assets
94
 7.
8. Early Nuclear Plant Retirements
95
 8. Intangible Assets
97
9. Fair Value of Financial Assets and Liabilities
97100
 
10. Derivative Financial Instruments
118122
 
11. Debt and Credit Agreements
132137
 
12. Income Taxes
136139
 
13. Nuclear Decommissioning
141Asset Retirement Obligations
14. Retirement Benefits
144
15. Severance
146
 16.
14. Retirement Benefits
150
15. Changes in Accumulated Other Comprehensive Income
149
17. Earnings Per Share and Equity
154
 18. Commitments
16. Earnings Per Share and ContingenciesEquity
155158
 19. Supplemental Financial Information
17. Commitments and Contingencies
166159
 20.
18. Supplemental Financial Information
170
19. Segment Information
173177

4
Table of Contents


 Page No.
ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
180191
 
Exelon Corporation
180191
 
Executive Overview
180191
 
Financial Results of Operations
181193
 
Significant 20172018 Transactions and Developments
189201
 
Exelon's Strategy and Outlook for 20172018 and Beyond
194206
 
Liquidity Considerations
195208
 
Other Key Business Drivers and Management Strategies
196209
 
Critical Accounting Policies and Estimates
202215
 
Results of Operations By Registrant
203217
 
Exelon Generation Company, LLC
204
Commonwealth Edison Company
212
PECO Energy Company
218
 
Commonwealth Edison Company
228
PECO Energy Company
235
Baltimore Gas and Electric Company
224242
 
Pepco Holdings LLC
231249
 
Potomac Electric Power Company
234252
 
Delmarva Power & Light Company
240259
 
Atlantic City Electric Company
248267
 
Liquidity and Capital Resources
253273
 
Contractual Obligations and Off-Balance Sheet Arrangements
266287
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
266288
ITEM 4.
CONTROLS AND PROCEDURES
275296
PART II.
OTHER INFORMATION
276OTHER INFORMATION
297
ITEM 1.
LEGAL PROCEEDINGS
276LEGAL PROCEEDINGS
297
ITEM 1A.
RISK FACTORS
276RISK FACTORS
297
ITEM 4.
MINE SAFETY DISCLOSURES
276297
ITEM 6.
EXHIBITS
276EXHIBITS
298
SIGNATURES
279301
 
Exelon Corporation
279301
 
Exelon Generation Company, LLC
280302
 
Commonwealth Edison Company
281303
 
PECO Energy Company
282304
 
Baltimore Gas and Electric Company
283305
 
Pepco Holdings LLC
284306
 
Potomac Electric Power Company
285307
 
Delmarva Power & Light Company
286308
 
Atlantic City Electric Company
287309


5
Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon Exelon Corporation
Generation Exelon Generation Company, LLC
ComEd Commonwealth Edison Company
PECO PECO Energy Company
BGE Baltimore Gas and Electric Company
Pepco Holdings or PHI Pepco Holdings LLC (formerly Pepco Holdings, Inc.)
Pepco Potomac Electric Power Company
Pepco Energy Services or PESPepco Energy Services, Inc. and its subsidiaries
PCIPotomac Capital Investment Corporation and its subsidiaries
DPL Delmarva Power & Light Company
ACE Atlantic City Electric Company
ACE Funding or ATFAtlantic City Electric Transition Funding LLC
BSCExelon Business Services Company, LLC
PHISCOPHI Service Company
Exelon CorporateExelon in its corporate capacity as a holding company
PHI CorporatePHI in its corporate capacity as a holding company
Registrants Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively
Utility Registrants ComEd, PECO, BGE, Pepco, DPL and ACE, collectively
AmerGenLegacy PHI AmerGen Energy Company,PHI, Pepco, DPL and ACE, collectively
ACE Funding or ATFAtlantic City Electric Transition Funding LLC
Antelope Valley Antelope Valley Solar Ranch One
BondCoBSC RSB BondCoExelon Business Services Company, LLC
CENG Constellation Energy Nuclear Group, LLC
ConectivConectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE
ConEdison Solutions The competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc., a subsidiary of Consolidated Edison, Inc.
Constellation Constellation Energy Group, Inc.
EEDCExelon Energy Delivery Company, LLC
EGR IVExGen Renewables IV, LLC
EGTP ExGen Texas Power, LLC
EGRExGen Renewables I, LLC
Entergy Entergy Nuclear FitzPatrick, LLC
Exelon CorporateExelon in its corporate capacity as a holding company
Exelon Transmission Company Exelon Transmission Company, LLC
Exelon Wind Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC
FitzPatrick James A. FitzPatrick nuclear generating station
Legacy PHIPCI PHI, Pepco, DPLPotomac Capital Investment Corporation and ACE, collectivelyits subsidiaries
PEC L.P. PECO Energy Capital, L.P.
PECO Trust III PECO Capital Trust III
PECO Trust IV PECO Energy Capital Trust IV
PETTPepco Energy Services or PES PECOPepco Energy Transition TrustServices, Inc. and its subsidiaries
PHI CorporatePHI in its corporate capacity as a holding company
PHISCOPHI Service Company
RPG Renewable Power Generation
SolGen SolGen, LLC
TMIThree Mile Island nuclear facility
UIIUnicom Investments, Inc.
VenturesExelon Ventures Company, LLC

6
Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations  
TMIThree Mile Island nuclear facility
UIIUnicom Investments, Inc.
Note “—” of the Exelon 20162017 Form 10-K Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 20162017 Annual Report on Form 10-K
Act 11Pennsylvania Act 11 of 2012
Act 129Pennsylvania Act 129 of 2008
AEC Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source
AEPSPennsylvania Alternative Energy Portfolio Standards
AEPS ActPennsylvania Alternative Energy Portfolio Standards Act of 2004, as amended
AESO Alberta Electric Systems Operator
AFUDC Allowance for Funds Used During Construction
AGE Albany Green Energy Project
AMI Advanced Metering Infrastructure
AMPAdvanced Metering Program
AOCI Accumulated Other Comprehensive Income
ARC Asset Retirement Cost
ARO Asset Retirement Obligation
ASCARP Accounting Standards CodificationAlternative Revenue Program
BGS Basic Generation Service
Block ContractsForward Purchase Energy Block Contracts
CAIRClean Air Interstate Rule
CAISO California ISO
CAMRFederal Clean Air Mercury RuleIndependent System Operator
CAP Customer Assistance Program
CCGTsCombined-Cycle Gas Turbines
CERCLA Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CES Clean Energy Standard
CFLCompact Fluorescent Light
Clean Air Act Clean Air Act of 1963, as amended
Clean Water Act Federal Water Pollution Control Amendments of 1972, as amended
Competition ActPennsylvania Electricity Generation Customer Choice and Competition Act of 1996
ConectivConectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE
Conectiv Energy Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010
CPUCCalifornia Public Utilities Commission
CSAPR Cross-State Air Pollution Rule
D.C. Circuit Court United States Court of Appeals for the District of Columbia Circuit
DCPSCDistrict of Columbia Public Service Commission
DC PLUG District of Columbia Power Line Undergrounding Initiative
DCPSCDistrict of Columbia Public Service Commission
Default Electricity Supply 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 BGSBasic Generation Service
DOE United States Department of Energy
DOEEDepartment of Energy & Environment
DOJ United States Department of Justice
DPSC Delaware Public Service Commission
DRPDirect Stock Purchase and Dividend Reinvestment Plan
DSPDefault Service Provider
EDFElectricite de France SA and its subsidiaries

7
Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations  
DRPDirect Stock Purchase and Dividend Reinvestment Plan
DSPDefault Service Provider
DSP ProgramDefault Service Provider Program
EDCsElectric distribution companies
EDFElectricite de France SA and its subsidiaries
EE&C Energy Efficiency and Conservation/Demand Response
EGSElectric Generation Supplier
EIMA Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EmPower Maryland A Maryland demand-side management program for Pepco and DPL
EPA United States Environmental Protection Agency
EPSA Electric Power Supply Association
ERCOT Electric Reliability Council of Texas
ERISA Employee Retirement Income Security Act of 1974, as amended
EROA Expected Rate of Return on Assets
ESPPEmployee Stock Purchase Plan
FASB Financial Accounting Standards Board
FEJA Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC Federal Energy Regulatory Commission
FRCC Florida Reliability Coordinating Council
GAAP Generally Accepted Accounting Principles in the United States
GCR Gas Cost Rate
GHG Greenhouse Gas
GSA Generation Supply Adjustment
GWh Gigawatt hour
Health Care Reform ActsPatient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010
HSR ActThe Hart-Scott-Rodino Antitrust Improvements Act of 1976
IBEW International Brotherhood of Electrical Workers
ICC Illinois Commerce Commission
ICE Intercontinental Exchange
Illinois ActIllinois Electric Service Customer Choice and Rate Relief Law of 1997
Illinois EPA Illinois Environmental Protection Agency
Illinois Settlement Legislation Legislation enacted in 2007 affecting electric utilities in Illinois
IntegrysIntegrys Energy Services, Inc.
IPA Illinois Power Agency
IRC Internal Revenue Code
IRS Internal Revenue Service
ISO Independent System Operator
ISO-NE Independent System Operator New England Inc.
ISO-NY Independent System Operator New York
kV Kilovolt
kW Kilowatt
kWh Kilowatt-hour
LIBOR London Interbank Offered Rate

8
Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
LLRW Low-Level Radioactive Waste
LT Plan Long-term renewable resources procurement plan
LTIP Long-Term Incentive Plan
MAPP Mid-Atlantic Power Pathway
MATS U.S. EPA Mercury and Air Toxics Rule
MBR Market Based Rates Incentive

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
MDE Maryland Department of the Environment
MDPSC Maryland Public Service Commission
MGP Manufactured Gas Plant
MISO Midcontinent Independent System Operator, Inc.
mmcf Million Cubic Feet
Moody’s Moody’s Investor Service
MOPR Minimum Offer Price Rule
MRV Market-Related Value
MW Megawatt
MWh Megawatt hour
n.m.not meaningful
NAAQS National Ambient Air Quality Standards
n.m.not meaningful
NAV Net Asset Value
NDT Nuclear Decommissioning Trust
NEIL Nuclear Electric Insurance Limited
NERC North American Electric Reliability Corporation
NGS Natural Gas Supplier
NJBPU New Jersey Board of Public Utilities
NJDEP New Jersey Department of Environmental Protection
NLRBNational Labor Relations Board
Non-Regulatory Agreements Units Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOSA Nuclear Operating Services Agreement
NPDES National Pollutant Discharge Elimination System
NRC Nuclear Regulatory Commission
NSPS New Source Performance Standards
NUGs Non-utility generators
NWPA Nuclear Waste Policy Act of 1982
NYMEX New York Mercantile Exchange
NYPSC New York Public Service Commission
OCI Other Comprehensive Income
OIESO Ontario Independent Electricity System Operator
OPC Office of People’s Counsel
OPEB Other Postretirement Employee Benefits
PA DEP Pennsylvania Department of Environmental Protection
PAPUC Pennsylvania Public Utility Commission
PCBPolychlorinated Biphenyl
PGC Purchased Gas Cost Clause
PJM PJM Interconnection, LLC
POLRProvider of Last Resort
PORPurchase of Receivables
PPAPower Purchase Agreement

9
Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations  
POLRProvider of Last Resort
PORPurchase of Receivables
PPAPower Purchase Agreement
Price-Anderson Act Price-Anderson Nuclear Industries Indemnity Act of 1957
Preferred StockOriginally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share
PRP Potentially Responsible Parties
PSEG Public Service Enterprise Group Incorporated
PURTAPennsylvania Public Realty Tax Act
PV Photovoltaic
RCRA Resource Conservation and Recovery Act of 1976, as amended
REC Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement Units Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RES Retail Electric Suppliers
RFP Request for Proposal
Rider Reconcilable Surcharge Recovery Mechanism
RGGIRegional Greenhouse Gas Initiative
RMC Risk Management Committee
ROE Return on equity
RPM PJM Reliability Pricing Model
RPS Renewable Energy Portfolio Standards
RSSA Reliability Support Services Agreement
RTEP Regional Transmission Expansion Plan
RTO Regional Transmission Organization
S&P Standard & Poor’s Ratings Services
SEC United States Securities and Exchange Commission
Senate Bill 1Maryland Senate Bill 1
SERC SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SGIGSmart Grid Investment Grant from DOE
SILO Sale-In, Lease-Out
SMPIPSmart Meter Procurement and Installation Plan
SNF Spent Nuclear Fuel
SOS Standard Offer Service
SPFPA Security, Police and Fire Professionals of America
SPP Southwest Power Pool
TCJATax Cuts and Jobs Act
Transition Bond Charge Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
Transition Bonds Transition Bonds issued by ACE Funding
UGSOAUnited Government Security Officers of America
Upstream Natural gas exploration and production activities
VIE Variable Interest Entity

10
Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
WECC Western Electric Coordinating Council
ZEC Zero Emission Credit, or Zero Emission Certificate
ZES Zero Emission Standard

11

FILING FORMAT
This combined Form 10-Q is being filed separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the Registrants' combined 20162017 Annual Report on Form 10-K 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 24,23, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 18,17, Commitments and Contingencies; and (3) 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.www.exeloncorp.com. Information contained on the Registrants’ websites shall not be deemed incorporated into, or to be a part of, this Report.

12




PART I. FINANCIAL INFORMATION
Item 1. Financial Statements




13


EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions, except per share data)2017 2016 2017 20162018 2017 2018 2017
Operating revenues              
Competitive businesses revenues$4,456
 $4,535
 $12,924
 $12,243
$4,971
 $4,455
 $14,387
 $12,955
Rate-regulated utility revenues4,313
 4,467
 12,225
 11,243
4,457
 4,259
 12,824
 12,034
Revenues from alternative revenue programs(25) 54
 (41) 191
Total operating revenues8,769
 9,002
 25,149
 23,486
9,403
 8,768
 27,170
 25,180
Operating expenses              
Competitive businesses purchased power and fuel2,316
 2,584
 7,268
 6,599
2,977
 2,316
 8,542
 7,268
Rate-regulated utility purchased power and fuel1,226
 1,170
 3,259
 2,863
1,355
 1,226
 3,832
 3,259
Operating and maintenance2,300
 2,338
 7,732
 7,677
2,346
 2,275
 7,036
 7,658
Depreciation and amortization1,002
 1,195
 2,814
 2,821
1,105
 1,002
 3,284
 2,814
Taxes other than income456
 449
 1,313
 1,168
469
 456
 1,342
 1,313
Total operating expenses7,300

7,736

22,386

21,128
8,252

7,275

24,036

22,312
(Loss) Gain on sales of assets(1) 1
 4
 41
(Loss) gain on sales of assets and businesses(5) (1) 55
 4
Bargain purchase gain7
 —
 233
 —
—
 7
 —
 233
Operating income1,475

1,267

3,000

2,399
1,146

1,499

3,189

3,105
Other income and (deductions)              
Interest expense, net(377) (506) (1,165) (1,148)(387) (377) (1,119) (1,165)
Interest expense to affiliates(9) (10) (29) (31)(6) (9) (19) (29)
Other, net237
 120
 725
 377
194
 210
 212
 643
Total other income and (deductions)(149)
(396)
(469)
(802)(199)
(176)
(926)
(551)
Income before income taxes1,326
 871
 2,531
 1,597
947
 1,323
 2,263
 2,554
Income taxes452
 340
 595
 625
137
 451
 262
 601
Equity in losses of unconsolidated affiliates(7) (5) (25) (16)(10) (7) (22) (25)
Net income867

526

1,911

956
800

865

1,979

1,928
Net income attributable to noncontrolling interests and preference stock dividends43
 36
 12
 26
Net income attributable to noncontrolling interests67
 42
 121
 21
Net income attributable to common shareholders$824

$490

$1,899

$930
$733

$823

$1,858

$1,907
Comprehensive income, net of income taxes              
Net income$867
 $526
 $1,911
 $956
$800
 $865
 $1,979
 $1,928
Other comprehensive income (loss), net of income taxes              
Pension and non-pension postretirement benefit plans:              
Prior service benefit reclassified to periodic benefit cost(14) (12) (42) (35)(17) (14) (50) (42)
Actuarial loss reclassified to periodic benefit cost49
 47
 147
 140
62
 49
 186
 147
Pension and non-pension postretirement benefit plan valuation adjustment3
 —
 (55) (3)5
 3
 22
 (55)
Unrealized gain (loss) on cash flow hedges—
 3
 5
 (4)
Unrealized gain (loss) on equity investments1
 (4) 5
 (10)
Unrealized gain on foreign currency translation4
 2
 7
 8
Unrealized gain on cash flow hedges—
 —
 12
 5
Unrealized gain on investments in unconsolidated affiliates—
 1
 3
 5
Unrealized gain (loss) on foreign currency translation2
 4
 (4) 7
Unrealized gain on marketable securities1
 —
 2
 —
—
 1
 —
 2
Other comprehensive income44

36

69

96
52

44

169

69
Comprehensive income911

562

1,980

1,052
852

909

2,148

1,997
Comprehensive income attributable to noncontrolling interests and preference stock dividends43
 31
 10
 21
Comprehensive income attributable to noncontrolling interests67
 42
 123
 19
Comprehensive income attributable to common shareholders$868
 $531
 $1,970
 $1,031
$785
 $867
 $2,025
 $1,978
              
Average shares of common stock outstanding:              
Basic962
 925
 941
 924
968
 962
 967
 941
Diluted965
 927
 943
 926
970
 965
 969
 943
Earnings per average common share:              
Basic$0.86
 $0.53
 $2.02
 $1.01
$0.76
 $0.86
 $1.92
 $2.03
Diluted$0.85
 $0.53
 $2.01
 $1.00
$0.76
 $0.85
 $1.92
 $2.02
Dividends declared per common share$0.33
 $0.32
 $0.98
 $0.95
$0.35
 $0.33
 $1.04
 $0.98
See the Combined Notes to Consolidated Financial Statements

14

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended 
 September 30,		Nine Months Ended
September 30,
(In millions)2017 20162018 2017
Cash flows from operating activities      
Net income$1,911
 $956
$1,979
 $1,928
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization3,999
 4,009
4,511
 3,999
Impairment of long-lived assets and losses on regulatory assets488
 274
49
 488
Gain on sales of assets(5) (41)
Gain on sales of assets and businesses(55) (5)
Bargain purchase gain(233) —
—
 (233)
Deferred income taxes and amortization of investment tax credits439
 623
97
 444
Net fair value changes related to derivatives149
 100
67
 149
Net realized and unrealized gains on nuclear decommissioning trust fund investments(429) (243)(21) (429)
Other non-cash operating activities603
 1,224
804
 603
Changes in assets and liabilities:      
Accounts receivable224
 (296)(167) 184
Inventories(87) 21
(24) (87)
Accounts payable and accrued expenses(593) 296
84
 (591)
Option premiums received (paid), net35
 (24)
Collateral (posted) received, net(100) 757
Option premiums (paid) received, net(36) 35
Collateral received (posted), net222
 (100)
Income taxes167
 527
166
 167
Pension and non-pension postretirement benefit contributions(344) (283)(362) (344)
Other assets and liabilities(547) (537)(639) (535)
Net cash flows provided by operating activities5,677

7,363
6,675

5,673
Cash flows from investing activities      
Capital expenditures(5,556) (6,368)(5,497) (5,556)
Proceeds from nuclear decommissioning trust fund sales6,848
 7,914
6,379
 6,848
Investment in nuclear decommissioning trust funds(7,044) (8,093)(6,553) (7,044)
Acquisition of businesses, net(208) (6,896)
Proceeds from sales of long-lived assets219
 49
Proceeds from termination of direct financing lease investment—
 360
Changes in restricted cash(67) (75)
Acquisition of assets and businesses, net(57) (208)
Proceeds from sales of assets and businesses90
 219
Other investing activities(2) (110)29
 (2)
Net cash flows used in investing activities(5,810)
(13,219)(5,609)
(5,743)
Cash flows from financing activities      
Changes in short-term borrowings(570) (1,014)(218) (570)
Proceeds from short-term borrowings with maturities greater than 90 days621
 195
126
 621
Repayments on short-term borrowings with maturities greater than 90 days(610) (452)(1) (610)
Issuance of long-term debt2,616
 4,488
2,664
 2,616
Retirement of long-term debt(1,728) (944)(1,480) (1,728)
Retirement of long-term debt to financing trust(250)
—
—
 (250)
Restricted proceeds from issuance of long-term debt—
 (30)
Redemption of preference stock—
 (190)
Sale of noncontrolling interest396
 —
—
 396
Dividends paid on common stock(921) (873)(999) (921)
Common stock issued from treasury stock1,150
 —
—
 1,150
Proceeds from employee stock plans61
 36
67
 61
Other financing activities(64) 35
(94) (64)
Net cash flows provided by financing activities701

1,251
65

701
Increase (Decrease) in cash and cash equivalents568
 (4,605)
Cash and cash equivalents at beginning of period635
 6,502
Cash and cash equivalents at end of period$1,203

$1,897
Increase in cash, cash equivalents and restricted cash1,131
 631
Cash, cash equivalents and restricted cash at beginning of period1,190
 914
Cash, cash equivalents and restricted cash at end of period$2,321

$1,545
See the Combined Notes to Consolidated Financial Statements

15

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
ASSETS      
Current assets      
Cash and cash equivalents$1,203
 $635
$1,918
 $898
Restricted cash and cash equivalents320
 253
240
 207
Deposit with IRS1,250
 1,250
Accounts receivable, net      
Customer3,854
 4,158
4,239
 4,445
Other950
 1,201
1,246
 1,132
Mark-to-market derivative assets699
 917
696
 976
Unamortized energy contract assets81
 88
42
 60
Inventories, net      
Fossil fuel and emission allowances387
 364
349
 340
Materials and supplies1,281
 1,274
1,316
 1,311
Regulatory assets1,264
 1,342
1,340
 1,267
Assets held for sale910
 —
Other1,435
 930
1,177
 1,260
Total current assets12,724

12,412
13,473

11,896
Property, plant and equipment, net73,067
 71,555
75,840
 74,202
Deferred debits and other assets      
Regulatory assets10,238
 10,046
8,002
 8,021
Nuclear decommissioning trust funds12,966
 11,061
12,464
 13,272
Investments634
 629
649
 640
Goodwill6,677
 6,677
6,677
 6,677
Mark-to-market derivative assets426
 492
449
 337
Unamortized energy contract assets407
 447
371
 395
Pledged assets for Zion Station decommissioning57
 113
Other1,277
 1,472
1,560
 1,330
Total deferred debits and other assets32,682

30,937
30,172

30,672
Total assets(a)
$118,473

$114,904
$119,485

$116,770

See the Combined Notes to Consolidated Financial Statements

16

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
LIABILITIES AND SHAREHOLDERS’ EQUITY      
Current liabilities      
Short-term borrowings$710
 $1,267
$834
 $929
Long-term debt due within one year3,164
 2,430
771
 2,088
Accounts payable3,132
 3,441
3,348
 3,532
Accrued expenses3,080
 3,460
1,964
 1,837
Payables to affiliates5
 8
5
 5
Regulatory liabilities553
 602
689
 523
Mark-to-market derivative liabilities178
 282
329
 232
Unamortized energy contract liabilities283
 407
158
 231
Renewable energy credit obligation261
 428
256
 352
PHI merger related obligation96
 151
63
 87
Liabilities held for sale788
 —
Other933
 981
935
 982
Total current liabilities12,395
 13,457
10,140
 10,798
Long-term debt31,701
 31,575
34,519
 32,176
Long-term debt to financing trusts389
 641
390
 389
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits19,250
 18,138
11,702
 11,235
Asset retirement obligations9,733
 9,111
9,747
 10,029
Pension obligations4,055
 4,248
3,385
 3,736
Non-pension postretirement benefit obligations1,977
 1,848
2,155
 2,093
Spent nuclear fuel obligation1,142
 1,024
1,164
 1,147
Regulatory liabilities4,549
 4,187
9,756
 9,865
Mark-to-market derivative liabilities410
 392
482
 409
Unamortized energy contract liabilities656
 830
497
 609
Payable for Zion Station decommissioning—
 14
Other1,899
 1,827
2,160
 2,097
Total deferred credits and other liabilities43,671
 41,619
41,048
 41,220
Total liabilities(a)
88,156

87,292
86,097

84,583
Commitments and contingencies
 

 
Shareholders’ equity      
Common stock (No par value, 2000 shares authorized, 961 shares and 924 shares outstanding at September 30, 2017 and December 31, 2016, respectively)18,862
 18,794
Treasury stock, at cost (2 shares and 35 shares at September 30, 2017 and December 31, 2016, respectively)(123) (2,327)
Common stock (No par value, 2,000 shares authorized, 967 shares and 963 shares outstanding at September 30, 2018 and December 31, 2017, respectively)19,063
 18,964
Treasury stock, at cost (2 shares at September 30, 2018 and December 31, 2017)(123) (123)
Retained earnings11,950
 12,030
14,949
 14,081
Accumulated other comprehensive loss, net(2,589) (2,660)(2,869) (3,026)
Total shareholders’ equity28,100

25,837
31,020

29,896
Noncontrolling interests2,217
 1,775
2,368
 2,291
Total equity30,317

27,612
33,388

32,187
Total liabilities and shareholders’ equity$118,473

$114,904
$119,485

$116,770
__________
(a)Exelon’s consolidated assets include $9,520$9,804 million and $8,893$9,597 million at September 30, 20172018 and December 31, 2016,2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,688$3,606 million and $3,356$3,618 million at September 30, 20172018 and December 31, 2016,2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 -— Variable Interest Entities.Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

17

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
(In millions, shares
in thousands)
Issued
Shares
 
Common
Stock
 
Treasury
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 
Total Shareholders'
Equity
Issued
Shares
 
Common
Stock
 
Treasury
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 
Total Shareholders'
Equity
Balance, December 31, 2016958,778
 $18,794
 $(2,327) $12,030
 $(2,660) $1,775
 $27,612
Balance, December 31, 2017965,168
 $18,964
 $(123) $14,081
 $(3,026) $2,291
 $32,187
Net income—
 —
 —
 1,899
 —
 12
 1,911
—
 —
 —
 1,858
 —
 121
 1,979
Long-term incentive plan activity2,911
 43
 —
 —
 —
 —
 43
2,677
 32
 —
 —
 —
 —
 32
Employee stock purchase plan issuances996
 61
 —
 —
 —
 —
 61
997
 67
 —
 —
 —
 —
 67
Common stock issued from treasury stock—
 —
 2,204
 (1,054) —
 —
 1,150
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 (11) (11)—
 —
 —
 —
 —
 (46) (46)
Sale of noncontrolling interests—
 (36) —
 —
 —
 443
 407
Common stock dividends—
 —
 —
 (925) —
 —
 (925)—
 —
 —
 (1,004) —
 —
 (1,004)
Other comprehensive income (loss), net of income taxes—
 —
 —
 —
 71
 (2) 69
Balance, September 30, 2017962,685
 $18,862
 $(123) $11,950
 $(2,589) $2,217
 $30,317
Other comprehensive income, net of income taxes—
 —
 —
 —
 167
 2
 169
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 —
 —
 14
 (10) —
 4
Balance, September 30, 2018968,842
 $19,063
 $(123) $14,949
 $(2,869) $2,368
 $33,388

See the Combined Notes to Consolidated Financial Statements

18


EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2017 2016 2017 20162018 2017 2018 2017
Operating revenues              
Operating revenues$4,455
 $4,533
 $12,918
 $12,234
$4,970
 $4,454
 $14,389
 $12,949
Operating revenues from affiliates296
 502
 894
 1,129
308
 296
 979
 894
Total operating revenues4,751

5,035

13,812

13,363
5,278

4,750

15,368

13,843
Operating expenses              
Purchased power and fuel2,315
 2,584
 7,267
 6,599
2,977
 2,315
 8,542
 7,267
Purchased power and fuel from affiliates16
 5
 19
 10
3
 16
 10
 19
Operating and maintenance1,203
 1,189
 4,335
 3,855
1,218
 1,205
 3,643
 4,343
Operating and maintenance from affiliates171
 147
 536
 478
152
 171
 483
 536
Depreciation and amortization410
 632
 1,046
 1,329
468
 410
 1,383
 1,046
Taxes other than income141
 136
 425
 380
143
 141
 414
 425
Total operating expenses4,256

4,693

13,628

12,651
4,961

4,258

14,475

13,636
(Loss) gain on sales of assets(2) —
 3
 31
(Loss) gain on sales of assets and businesses(6) (2) 48
 3
Bargain purchase gain7
 —
 233
 —
—
 7
 —
 233
Operating income500

342

420

743
311

497

941

443
Other income and (deductions)              
Interest expense, net(103) (67) (313) (243)(93) (103) (278) (313)
Interest expense to affiliates(10) (10) (29) (30)(8) (10) (27) (29)
Other, net209
 185
 648
 395
179
 209
 164
 648
Total other income and (deductions)96

108

306

122
78

96

(141)
306
Income before income taxes596
 450
 726
 865
389
 593
 800
 749
Income taxes240
 173
 209
 293
78
 239
 110
 215
Equity in losses of unconsolidated affiliates(8) (6) (26) (16)(11) (8) (23) (26)
Net income348

271

491

556
300

346

667

508
Net income attributable to noncontrolling interests43
 35
 12
 18
66
 42
 120
 21
Net income attributable to membership interest$305

$236

$479

$538
$234

$304

$547

$487
Comprehensive income, net of income taxes              
Net income$348
 $271
 $491
 $556
$300
 $346
 $667
 $508
Other comprehensive income (loss), net of income taxes              
Unrealized gain (loss) on cash flow hedges—
 1
 5
 (3)
Unrealized gain (loss) on equity investments—
 —
 4
 (4)
Unrealized gain on foreign currency translation4
 2
 7
 8
Unrealized gain on marketable securities—
 1
 —
 1
Unrealized gain on cash flow hedges—
 —
 12
 5
Unrealized gain on investments in unconsolidated affiliates—
 —
 3
 4
Unrealized gain (loss) on foreign currency translation2
 4
 (4) 7
Other comprehensive income4

4

16

2
2

4

11

16
Comprehensive income352

275

507

558
302

350

678

524
Comprehensive income attributable to noncontrolling interests43
 30
 10
 13
66
 42
 122
 19
Comprehensive income attributable to membership interest$309
 $245
 $497
 $545
$236
 $308
 $556
 $505

See the Combined Notes to Consolidated Financial Statements

19

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended 
 September 30,		Nine Months Ended
September 30,
(In millions)2017 20162018 2017
Cash flows from operating activities      
Net income$491
 $556
$667
 $508
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization2,231
 2,516
2,608
 2,231
Impairment of long-lived assets485
 209
49
 485
Gain on sales of assets(3) (31)
Gain on sales of assets and businesses(48) (3)
Bargain purchase gain(233) —
—
 (233)
Deferred income taxes and amortization of investment tax credits(184) (133)(278) (179)
Net fair value changes related to derivatives160
 112
73
 160
Net realized and unrealized gains on nuclear decommissioning trust fund investments(429) (243)(21) (429)
Other non-cash operating activities132
 129
187
 132
Changes in assets and liabilities:
 

 
Accounts receivable106
 26
126
 66
Receivables from and payables to affiliates, net27
 (56)(7) 27
Inventories(43) 18
(10) (43)
Accounts payable and accrued expenses(257) 9
(59) (255)
Option premiums received (paid), net35
 (24)
Collateral (posted) received, net(77) 759
Option premiums (paid) received, net(36) 35
Collateral received (posted), net228
 (77)
Income taxes154
 202
220
 154
Pension and non-pension postretirement benefit contributions(122) (122)(134) (122)
Other assets and liabilities(203) (204)(154) (187)
Net cash flows provided by operating activities2,270

3,723
3,411

2,270
Cash flows from investing activities      
Capital expenditures(1,654) (2,651)(1,660) (1,654)
Proceeds from nuclear decommissioning trust fund sales6,848
 7,914
6,379
 6,848
Investment in nuclear decommissioning trust funds(7,044) (8,093)(6,553) (7,044)
Acquisition of businesses, net(208) (255)
Proceeds from sale of long-lived assets218
 30
Changes in restricted cash(28) (39)
Acquisition of assets and businesses, net(57) (208)
Proceeds from sales of assets and businesses90
 218
Other investing activities(35) (184)(5) (35)
Net cash flows used in investing activities(1,903)
(3,278)(1,806)
(1,875)
Cash flows from financing activities      
Changes in short-term borrowings(620) —
—
 (620)
Proceeds from short-term borrowings with maturities greater than 90 days121
 195
1
 121
Repayments of short-term borrowings with maturities greater than 90 days(110) (152)(1) (110)
Issuance of long-term debt789
 338
14
 789
Retirement of long-term debt(541) (164)(100) (541)
Changes in Exelon intercompany money pool91
 (785)(54) 91
Distributions to member(494) (167)(688) (494)
Contributions from member102

142
54

102
Sale of noncontrolling interest396
 —
—
 396
Other financing activities(31) 92
(46) (31)
Net cash flows used in financing activities(297)
(501)(820)
(297)
Increase (Decrease) in cash and cash equivalents70
 (56)
Cash and cash equivalents at beginning of period290
 431
Cash and cash equivalents at end of period$360

$375
Increase in cash, cash equivalents and restricted cash785
 98
Cash, cash equivalents and restricted cash at beginning of period554
 448
Cash, cash equivalents and restricted cash at end of period$1,339

$546

See the Combined Notes to Consolidated Financial Statements

20

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
ASSETS      
Current assets      
Cash and cash equivalents$360
 $290
$1,187
 $416
Restricted cash and cash equivalents186
 158
152
 138
Accounts receivable, net      
Customer2,339
 2,433
2,545
 2,697
Other275
 558
278
 321
Mark-to-market derivative assets699
 917
696
 976
Receivables from affiliates127
 156
182
 140
Unamortized energy contract assets81
 88
42
 60
Inventories, net      
Fossil fuel and emission allowances298
 292
255
 264
Materials and supplies917
 935
948
 937
Assets held for sale910
 —
Other1,157
 701
854
 933
Total current assets6,439

6,528
8,049

6,882
Property, plant and equipment, net24,793
 25,585
24,168
 24,906
Deferred debits and other assets      
Nuclear decommissioning trust funds12,966
 11,061
12,464
 13,272
Investments429
 418
433
 433
Goodwill47
 47
47
 47
Mark-to-market derivative assets416
 476
449
 334
Prepaid pension asset1,535
 1,595
1,472
 1,502
Pledged assets for Zion Station decommissioning57
 113
Unamortized energy contract assets406
 447
370
 395
Deferred income taxes8
 16
25
 16
Other648
 688
730
 670
Total deferred debits and other assets16,512

14,861
15,990

16,669
Total assets(a)
$47,744

$46,974
$48,207

$48,457

See the Combined Notes to Consolidated Financial Statements

21

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
LIABILITIES AND EQUITY      
Current liabilities      
Short-term borrowings$92
 $699
$—
 $2
Long-term debt due within one year1,659
 1,117
336
 346
Accounts payable1,492
 1,610
1,450
 1,773
Accrued expenses797
 989
1,200
 1,022
Payables to affiliates136
 137
144
 123
Borrowings from Exelon intercompany money pool146
 55
—
 54
Mark-to-market derivative liabilities158
 263
305
 211
Unamortized energy contract liabilities52
 72
33
 43
Renewable energy credit obligation261
 428
256
 352
Liabilities held for sale788
 —
Other266
 313
255
 265
Total current liabilities5,059
 5,683
4,767
 4,191
Long-term debt6,956
 7,202
7,605
 7,734
Long-term debt to affiliate913
 922
901
 910
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits5,596
 5,585
3,532
 3,811
Asset retirement obligations9,548
 8,922
9,521
 9,844
Non-pension postretirement benefit obligations919
 930
903
 916
Spent nuclear fuel obligation1,142
 1,024
1,164
 1,147
Payables to affiliates2,972
 2,608
2,959
 3,065
Mark-to-market derivative liabilities153
 153
237
 174
Unamortized energy contract liabilities57
 80
23
 48
Payable for Zion Station decommissioning—
 14
Other632
 595
635
 658
Total deferred credits and other liabilities21,019
 19,911
18,974
 19,663
Total liabilities(a)
33,947
 33,718
32,247
 32,498
Commitments and contingencies
 

 
Equity      
Member’s equity      
Membership interest9,357
 9,261
9,411
 9,357
Undistributed earnings2,260
 2,275
4,214
 4,349
Accumulated other comprehensive loss, net(36) (54)(31) (37)
Total member’s equity11,581
 11,482
13,594
 13,669
Noncontrolling interests2,216
 1,774
2,366
 2,290
Total equity13,797
 13,256
15,960
 15,959
Total liabilities and equity$47,744
 $46,974
$48,207
 $48,457
__________
(a)Generation’s consolidated assets include $9,477$9,768 million and $8,817$9,556 million at September 30, 20172018 and December 31, 2016,2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,576$3,528 million and $3,170$3,516 million at September 30, 20172018 and December 31, 2016,2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 -— Variable Interest Entities.Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

22

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)
 Member’s Equity    
(In millions)
Membership
Interest
 
Undistributed
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 Total Equity
Balance, December 31, 2016$9,261
 $2,275
 $(54) $1,774
 $13,256
Net income—
 479
 —
 12
 491
Changes in equity of noncontrolling interests—
 —
 —
 (11) (11)
Sale of noncontrolling interest(36) —
 —
 443
 407
Distribution of net retirement benefit obligation to member33
 —
 —
 —
 33
Allocation of tax benefit from member99
 —
 —
 —
 99
Distributions to member—
 (494) —
 —
 (494)
Other comprehensive income (loss), net of income taxes—
 —
 18
 (2) 16
Balance, September 30, 2017$9,357

$2,260

$(36)
$2,216

$13,797
 Member’s Equity    
(In millions)
Membership
Interest
 
Undistributed
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 Total Equity
Balance, December 31, 2017$9,357
 $4,349
 $(37) $2,290
 $15,959
Net income—
 547
 —
 120
 667
Changes in equity of noncontrolling interests—
 —
 —
 (46) (46)
Contribution from member54
 —
 —
 —
 54
Distributions to member—
 (688) —
 —
 (688)
Other comprehensive income, net of income taxes—
 —
 9
 2
 11
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 6
 (3) —
 3
Balance, September 30, 2018$9,411

$4,214

$(31)
$2,366

$15,960

See the Combined Notes to Consolidated Financial Statements

23


COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2017 2016 2017 20162018 2017 2018 2017
Operating revenues              
Electric operating revenues$1,568
 $1,493
 $4,215
 $4,019
$1,609
 $1,552
 $4,512
 $4,167
Revenues from alternative revenue programs(15) 16
 (27) 48
Operating revenues from affiliates3
 4
 12
 12
4
 3
 23
 12
Total operating revenues1,571

1,497

4,227

4,031
1,598

1,571

4,508

4,227
Operating expenses              
Purchased power489
 435
 1,178
 1,104
496
 489
 1,281
 1,178
Purchased power from affiliate40
 19
 63
 37
123
 40
 421
 63
Operating and maintenance277
 327
 897
 950
276
 277
 785
 897
Operating and maintenance from affiliate69
 50
 199
 163
61
 69
 189
 199
Depreciation and amortization212
 196
 631
 574
237
 212
 696
 631
Taxes other than income80
 82
 223
 222
82
 80
 238
 223
Total operating expenses1,167

1,109

3,191

3,050
1,275

1,167

3,610

3,191
Gain on sales of assets—
 1
 —
 6
—
 —
 5
 —
Operating income404

389

1,036

987
323

404

903

1,036
Other income and (deductions)              
Interest expense, net(86) (194) (265) (364)(82) (86) (251) (265)
Interest expense to affiliates(3) (3) (10) (10)(3) (3) (10) (10)
Other, net5
 (80) 14
 (72)7
 5
 21
 14
Total other income and (deductions)(84)
(277)
(261)
(446)(78)
(84)
(240)
(261)
Income before income taxes320
 112
 775
 541
245
 320
 663
 775
Income taxes131
 75
 328
 244
52
 131
 140
 328
Net income$189

$37

$447

$297
$193

$189

$523

$447
Comprehensive income$189
 $37
 $447
 $297
$193
 $189
 $523
 $447

See the Combined Notes to Consolidated Financial Statements

24

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended 
 September 30,		Nine Months Ended
September 30,
(In millions)2017 20162018 2017
Cash flows from operating activities      
Net income$447
 $297
$523
 $447
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization631
 574
696
 631
Deferred income taxes and amortization of investment tax credits455
 398
214
 455
Other non-cash operating activities112
 122
187
 112
Changes in assets and liabilities:      
Accounts receivable31
 (55)(190) 31
Receivables from and payables to affiliates, net346
 (9)8
 346
Inventories6
 4
4
 6
Accounts payable and accrued expenses(706) 145
(38) (706)
Collateral posted, net(22) (2)(10) (22)
Income taxes(205) 206
(65) (205)
Pension and non-pension postretirement benefit contributions(38) (35)(41) (38)
Other assets and liabilities63
 104
(170) 63
Net cash flows provided by operating activities1,120

1,749
1,118

1,120
Cash flows from investing activities      
Capital expenditures(1,698) (1,950)(1,540) (1,698)
Changes in restricted cash(50) —
Other investing activities17
 31
22
 17
Net cash flows used in investing activities(1,731)
(1,919)(1,518)
(1,681)
Cash flows from financing activities      
Changes in short-term borrowings—
 (284)
Issuance of long-term debt1,000
 1,200
1,350
 1,000
Retirement of long-term debt(425) (665)(840) (425)
Contributions from parent567
 188
387
 567
Dividends paid on common stock(316) (275)(345) (316)
Other financing activities(14) (17)(16) (14)
Net cash flows provided by financing activities812

147
536

812
Increase (Decrease) in cash and cash equivalents201
 (23)
Cash and cash equivalents at beginning of period56
 67
Cash and cash equivalents at end of period$257

$44
Increase in cash, cash equivalents and restricted cash136
 251
Cash, cash equivalents and restricted cash at beginning of period144
 58
Cash, cash equivalents and restricted cash at end of period$280

$309

See the Combined Notes to Consolidated Financial Statements

25


COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2017 December 31, 2016
ASSETS   
Current assets   
Cash and cash equivalents$257
 $56
Restricted cash52
 2
Accounts receivable, net   
Customer496
 528
Other172
 218
Receivables from affiliates18
 356
Inventories, net152
 159
Regulatory assets187
 190
Other67
 45
Total current assets1,401

1,554
Property, plant and equipment, net20,353
 19,335
Deferred debits and other assets   
Regulatory assets1,387
 977
Investments6
 6
Goodwill2,625
 2,625
Receivables from affiliates2,438
 2,170
Prepaid pension asset1,236
 1,343
Other203
 325
Total deferred debits and other assets7,895

7,446
Total assets$29,649

$28,335

See the Combined Notes to Consolidated Financial Statements

26

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2017 December 31, 2016
LIABILITIES AND SHAREHOLDERS’ EQUITY   
Current liabilities   
Long-term debt due within one year$840
 $425
Accounts payable579
 645
Accrued expenses305
 1,250
Payables to affiliates51
 65
Customer deposits114
 121
Regulatory liabilities249
 329
Mark-to-market derivative liability20
 19
Other88
 84
Total current liabilities2,246
 2,938
Long-term debt6,760
 6,608
Long-term debt to financing trust205
 205
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits6,091
 5,364
Asset retirement obligations110
 119
Non-pension postretirement benefits obligations224
 239
Regulatory liabilities3,735
 3,369
Mark-to-market derivative liability257
 239
Other577
 529
Total deferred credits and other liabilities10,994
 9,859
Total liabilities20,205
 19,610
Commitments and contingencies
 
Shareholders’ equity   
Common stock1,588
 1,588
Other paid-in capital6,738
 6,150
Retained deficit unappropriated(1,639) (1,639)
Retained earnings appropriated2,757
 2,626
Total shareholders’ equity9,444
 8,725
Total liabilities and shareholders’ equity$29,649
 $28,335
(In millions)September 30, 2018 December 31, 2017
ASSETS   
Current assets   
Cash and cash equivalents$124
 $76
Restricted cash12
 5
Accounts receivable, net   
Customer590
 559
Other450
 266
Receivables from affiliates13
 13
Inventories, net146
 152
Regulatory assets256
 225
Other94
 68
Total current assets1,685

1,364
Property, plant and equipment, net21,642
 20,723
Deferred debits and other assets   
Regulatory assets1,229
 1,054
Investments6
 6
Goodwill2,625
 2,625
Receivables from affiliates2,469
 2,528
Prepaid pension asset1,083
 1,188
Other380
 238
Total deferred debits and other assets7,792

7,639
Total assets$31,119

$29,726

See the Combined Notes to Consolidated Financial Statements


27

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2018 December 31, 2017
LIABILITIES AND SHAREHOLDERS’ EQUITY   
Current liabilities   
Long-term debt due within one year$300
 $840
Accounts payable576
 568
Accrued expenses253
 327
Payables to affiliates82
 74
Customer deposits111
 112
Regulatory liabilities320
 249
Mark-to-market derivative liability24
 21
Other90
 103
Total current liabilities1,756
 2,294
Long-term debt7,800
 6,761
Long-term debt to financing trust205
 205
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits3,744
 3,469
Asset retirement obligations115
 111
Non-pension postretirement benefits obligations206
 219
Regulatory liabilities6,318
 6,328
Mark-to-market derivative liability235
 235
Other633
 562
Total deferred credits and other liabilities11,251
 10,924
Total liabilities21,012
 20,184
Commitments and contingencies
 
Shareholders’ equity   
Common stock1,588
 1,588
Other paid-in capital7,209
 6,822
Retained deficit unappropriated(1,639) (1,639)
Retained earnings appropriated2,949
 2,771
Total shareholders’ equity10,107
 9,542
Total liabilities and shareholders’ equity$31,119
 $29,726

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
(In millions)
Common
Stock
 
Other
Paid-In
Capital
 
Retained Deficit
Unappropriated
 
Retained
Earnings
Appropriated
 
Total
Shareholders’
Equity
Common
Stock
 
Other
Paid-In
Capital
 
Retained Deficit
Unappropriated
 
Retained
Earnings
Appropriated
 
Total
Shareholders’
Equity
Balance, December 31, 2016$1,588
 $6,150
 $(1,639) $2,626
 $8,725
Balance, December 31, 2017$1,588
 $6,822
 $(1,639) $2,771
 $9,542
Net income—
 —
 447
 —
 447
—
 —
 523
 —
 523
Appropriation of retained earnings for future dividends—
 —
 (447) 447
 —
—
 —
 (523) 523
 —
Common stock dividends—
 —
 —
 (316) (316)—
 —
 —
 (345) (345)
Contributions from parent—
 567
 —
 —
 567
—
 387
 —
 —
 387
Parent tax matter indemnification—
 21
 —
 —
 21
Balance, September 30, 2017$1,588

$6,738

$(1,639)
$2,757

$9,444
Balance, September 30, 2018$1,588

$7,209

$(1,639)
$2,949

$10,107

See the Combined Notes to Consolidated Financial Statements


28


PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2017 2016 2017 20162018 2017 2018 2017
Operating revenues              
Electric operating revenues$660
 $738
 $1,798
 $1,966
$697
 $660
 $1,886
 $1,798
Natural gas operating revenues53
 48
 338
 322
57
 53
 382
 338
Revenues from alternative revenue programs1
 —
 2
 —
Operating revenues from affiliates2
 2
 5
 5
2
 2
 5
 5
Total operating revenues715

788

2,141

2,293
757

715

2,275

2,141
Operating expenses              
Purchased power190
 171
 483
 466
215
 190
 576
 483
Purchased fuel14
 10
 126
 110
14
 14
 148
 126
Purchased power from affiliate31
 91
 110
 233
34
 31
 94
 110
Operating and maintenance161
 168
 488
 501
184
 161
 572
 488
Operating and maintenance from affiliates36
 31
 107
 103
35
 36
 114
 107
Depreciation and amortization72
 67
 213
 201
75
 72
 224
 213
Taxes other than income42
 46
 116
 126
46
 42
 125
 116
Total operating expenses546

584

1,643

1,740
603

546

1,853

1,643
Gain on sales of assets—
 —
 1
 —
Operating income169

204

498

553
154

169

423

498
Other income and (deductions)              
Interest expense, net(28) (27) (84) (83)(28) (28) (85) (84)
Interest expense to affiliates(3) (3) (9) (9)(4) (3) (11) (9)
Other, net2
 2
 6
 6
2
 2
 4
 6
Total other income and (deductions)(29)
(28)
(87)
(86)(30)
(29)
(92)
(87)
Income before income taxes140
 176
 411

467
124
 140
 331

411
Income taxes28
 54
 84
 121
(2) 28
 (5) 84
Net income$112

$122

$327

$346
$126

$112

$336

$327
Comprehensive income$112
 $122
 $327
 $346
$126
 $112
 $336
 $327

See the Combined Notes to Consolidated Financial Statements


29

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months Ended 
 September 30,		Nine Months Ended
September 30,
(In millions)2017 20162018 2017
Cash flows from operating activities      
Net income$327
 $346
$336
 $327
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization213
 201
224
 213
Gain on sales of assets(1) —
Deferred income taxes and amortization of investment tax credits37
 69
5
 37
Other non-cash operating activities38
 49
41
 38
Changes in assets and liabilities:      
Accounts receivable45
 (50)(85) 45
Receivables from and payables to affiliates, net(10) 9
1
 (10)
Inventories(5) 5
(13) (5)
Accounts payable and accrued expenses(41) (12)(1) (41)
Income taxes51
 43
(16) 51
Pension and non-pension postretirement benefit contributions(23) (29)(25) (23)
Other assets and liabilities(29) (49)26
 (29)
Net cash flows provided by operating activities603

582
492

603
Cash flows from investing activities      
Capital expenditures(537) (448)(615) (537)
Changes in Exelon intercompany money pool74
 —
—
 74
Other investing activities6
 10
6
 6
Net cash flows used in investing activities(457)
(438)(609)
(457)
Cash flows from financing activities      
Issuance of long-term debt325
 300
700
 325
Restricted proceeds from issuance of long-term debt—
 (30)
Retirement of long-term debt(500) —
Contributions from parent16
 18
71
 16
Dividends paid on common stock(216) (208)(300) (216)
Other financing activities(4) (3)(22) (4)
Net cash flows provided by financing activities121

77
Increase in cash and cash equivalents267
 221
Cash and cash equivalents at beginning of period63
 295
Cash and cash equivalents at end of period$330

$516
Net cash flows (used in) provided by financing activities(51)
121
(Decrease) increase in cash, cash equivalents and restricted cash(168) 267
Cash, cash equivalents and restricted cash at beginning of period275
 67
Cash, cash equivalents and restricted cash at end of period$107

$334

See the Combined Notes to Consolidated Financial Statements

30

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
ASSETS      
Current assets      
Cash and cash equivalents$330
 $63
$102
 $271
Restricted cash and cash equivalents4
 4
5
 4
Accounts receivable, net      
Customer240
 306
307
 327
Other125
 131
190
 105
Receivables from affiliates—
 4
Receivable from Exelon intercompany pool57
 131
Inventories, net      
Fossil fuel36
 35
39
 31
Materials and supplies31
 27
35
 30
Prepaid utility taxes41
 9
32
 8
Regulatory assets36
 29
84
 29
Other16
 18
19
 17
Total current assets916

757
813

822
Property, plant and equipment, net7,875
 7,565
8,461
 8,053
Deferred debits and other assets      
Regulatory assets1,773
 1,681
448
 381
Investments24
 25
26
 25
Receivable from affiliates533
 438
489
 537
Prepaid pension asset347
 345
350
 340
Other12
 20
34
 12
Total deferred debits and other assets2,689

2,509
1,347

1,295
Total assets$11,480

$10,831
$10,621

$10,170

See the Combined Notes to Consolidated Financial Statements

31

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Long-term debt due within one year$500
 $—
$—
 $500
Accounts payable285
 342
387
 370
Accrued expenses132
 104
89
 114
Payables to affiliates48
 63
53
 53
Customer deposits64
 61
67
 66
Regulatory liabilities159
 127
159
 141
Other28
 30
31
 23
Total current liabilities1,216
 727
786
 1,267
Long-term debt2,402
 2,580
3,083
 2,403
Long-term debt to financing trusts184
 184
184
 184
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits3,170
 3,006
1,909
 1,789
Asset retirement obligations27
 28
27
 27
Non-pension postretirement benefits obligations289
 289
288
 288
Regulatory liabilities560
 517
581
 549
Other90
 85
79
 86
Total deferred credits and other liabilities4,136
 3,925
2,884
 2,739
Total liabilities7,938
 7,416
6,937
 6,593
Commitments and contingencies
 

 
Shareholder’s equity      
Common stock2,489
 2,473
2,560
 2,489
Retained earnings1,052
 941
1,124
 1,087
Accumulated other comprehensive income, net1
 1
—
 1
Total shareholder’s equity3,542
 3,415
3,684
 3,577
Total liabilities and shareholder's equity$11,480
 $10,831
$10,621
 $10,170

See the Combined Notes to Consolidated Financial Statements


32

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
(In millions)
Common
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income, net
 
Total
Shareholder's
Equity
Common
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income, net
 
Total
Shareholder's
Equity
Balance, December 31, 2016$2,473
 $941
 $1
 $3,415
Balance, December 31, 2017$2,489
 $1,087
 $1
 $3,577
Net income—
 327
 —
 327
—
 336
 —
 336
Common stock dividends—
 (216) —
 (216)—
 (300) —
 (300)
Allocation of tax benefit from parent16
 —
 —
 16
Balance, September 30, 2017$2,489

$1,052

$1

$3,542
Contributions from parent71
 —
 —
 71
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 1
 (1) —
Balance, September 30, 2018$2,560

$1,124

$—

$3,684

See the Combined Notes to Consolidated Financial Statements


33


BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2017 2016 2017 20162018 2017 2018 2017
Operating revenues              
Electric operating revenues$657
 $733
 $1,890
 $1,993
$652
 $626
 $1,847
 $1,811
Natural gas operating revenues78
 72
 461
 412
79
 73
 527
 438
Revenues from alternative revenue programs(6) 36
 (23) 102
Operating revenues from affiliates3
 7
 12
 16
6
 3
 18
 12
Total operating revenues738

812

2,363

2,421
731

738

2,369

2,363
Operating expenses              
Purchased power159
 164
 407
 399
183
 159
 510
 407
Purchased fuel13
 14
 118
 109
21
 13
 176
 118
Purchased power from affiliate97
 182
 328
 486
68
 97
 195
 328
Operating and maintenance138
 150
 421
 494
144
 138
 462
 421
Operating and maintenance from affiliates37
 28
 111
 94
38
 37
 116
 111
Depreciation and amortization109
 101
 348
 307
110
 109
 358
 348
Taxes other than income61
 58
 180
 172
64
 61
 188
 180
Total operating expenses614

697

1,913

2,061
628

614

2,005

1,913
Gain on sales of assets—
 —
 1
 —
Operating income124

115

450

360
103

124

365

450
Other income and (deductions)              
Interest expense, net(24) (24) (69) (64)(27) (24) (78) (69)
Interest expense to affiliates(2) (4) (11) (12)—
 (2) —
 (11)
Other, net4
 5
 12
 16
5
 4
 14
 12
Total other income and (deductions)(22)
(23)
(68)
(60)(22)
(22)
(64)
(68)
Income before income taxes102
 92
 382

300
81
 102
 301

382
Income taxes40
 36
 151
 109
18
 40
 59
 151
Net income62

56

231

191
$63

$62

$242

$231
Preference stock dividends—
 2
 —
 8
Net income attributable to common shareholder$62

$54

$231

$183
       
Comprehensive income$62
 $56
 $231
 $191
$63
 $62
 $242
 $231
Comprehensive income attributable to preference stock dividends—
 2
 —
 8
Comprehensive income attributable to common shareholder$62
 $54
 $231
 $183

See the Combined Notes to Consolidated Financial Statements


34

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended 
 September 30,		Nine Months Ended
September 30,
(In millions)2017 20162018 2017
Cash flows from operating activities      
Net income$231
 $191
$242
 $231
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization348
 307
358
 348
Impairment of long-lived assets and losses on regulatory assets—
 52
Deferred income taxes and amortization of investment tax credits141
 54
82
 141
Other non-cash operating activities52
 109
42
 52
Changes in assets and liabilities:      
Accounts receivable95
 (50)72
 95
Receivables from and payables to affiliates, net(13) (10)(4) (13)
Inventories(18) (7)(8) (18)
Accounts payable and accrued expenses(25) 43
(3) (25)
Collateral received, net1
 —
Income taxes12
 19
(48) 12
Pension and non-pension postretirement benefit contributions(50) (46)(50) (50)
Other assets and liabilities(69) (2)(9) (72)
Net cash flows provided by operating activities704

660
675

701
Cash flows from investing activities      
Capital expenditures(615) (611)(667) (615)
Changes in restricted cash23
 (22)
Other investing activities6
 19
8
 6
Net cash flows used in investing activities(586)
(614)(659)
(609)
Cash flows from financing activities      
Changes in short-term borrowings(45) (210)(77) (45)
Issuance of long-term debt300
 850
300
 300
Retirement of long-term debt(41) (39)—
 (41)
Retirement of long-term debt to financing trust(250) —
—
 (250)
Redemption of preference stock—
 (190)
Dividends paid on preference stock—
 (8)
Dividends paid on common stock(148) (134)(157) (148)
Contributions from parent77
 28
18
 77
Other financing activities(5) (11)(2) (5)
Net cash flows (used in) provided by financing activities(112)
286
Increase in cash and cash equivalents6
 332
Cash and cash equivalents at beginning of period23
 9
Cash and cash equivalents at end of period$29

$341
Net cash flows provided by (used in) financing activities82

(112)
Increase (decrease) in cash, cash equivalents and restricted cash98
 (20)
Cash, cash equivalents and restricted cash at beginning of period18
 50
Cash, cash equivalents and restricted cash at end of period$116

$30

See the Combined Notes to Consolidated Financial Statements

35

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
ASSETS      
Current assets      
Cash and cash equivalents$29
 $23
$113
 $17
Restricted cash and cash equivalents1
 24
3
 1
Accounts receivable, net      
Customer288
 395
296
 375
Other86
 102
96
 94
Receivables from affiliates—
 1
Inventories, net      
Gas held in storage46
 30
46
 37
Materials and supplies40
 38
39
 40
Prepaid utility taxes—
 15
—
 69
Regulatory assets208
 208
195
 174
Other4
 7
10
 3
Total current assets702

842
798

811
Property, plant and equipment, net7,418
 7,040
8,039
 7,602
Deferred debits and other assets      
Regulatory assets497
 504
402
 397
Investments5
 12
5
 5
Prepaid pension asset297
 297
290
 285
Other4
 9
7
 4
Total deferred debits and other assets803

822
704

691
Total assets(a)
$8,923

$8,704
Total assets$9,541

$9,104

See the Combined Notes to Consolidated Financial Statements

36

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2017 December 31, 2016
LIABILITIES AND SHAREHOLDERS’ EQUITY   
Current liabilities   
Short-term borrowings$—
 $45
Long-term debt due within one year—
 41
Accounts payable218
 205
Accrued expenses147
 175
Payables to affiliates42
 55
Customer deposits114
 110
Regulatory liabilities63
 50
Other28
 26
Total current liabilities612
 707
Long-term debt2,577
 2,281
Long-term debt to financing trust—
 252
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits2,366
 2,219
Asset retirement obligations23
 21
Non-pension postretirement benefits obligations201
 205
Regulatory liabilities84
 110
Other52
 61
Total deferred credits and other liabilities2,726
 2,616
Total liabilities(a)
5,915
 5,856
Commitments and contingencies   
Shareholders’ equity   
Common stock1,498
 1,421
Retained earnings1,510
 1,427
Total shareholders' equity3,008
 2,848
Total liabilities and shareholders’ equity$8,923
 $8,704
__________
(a)BGE’s consolidated assets include $26 million at December 31, 2016 of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $42 million at December 31, 2016 of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. BGE no longer has interests in any VIEs as of September 30, 2017. See Note 3 - Variable Interest Entities.

See the Combined Notes to Consolidated Financial Statements
(In millions)September 30, 2018 December 31, 2017
LIABILITIES AND SHAREHOLDERS’ EQUITY   
Current liabilities   
Short-term borrowings$—
 $77
Accounts payable277
 265
Accrued expenses146
 164
Payables to affiliates47
 52
Customer deposits119
 116
Regulatory liabilities95
 62
Other23
 24
Total current liabilities707
 760
Long-term debt2,876
 2,577
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits1,345
 1,244
Asset retirement obligations24
 23
Non-pension postretirement benefits obligations200
 202
Regulatory liabilities1,070
 1,101
Other75
 56
Total deferred credits and other liabilities2,714
 2,626
Total liabilities6,297
 5,963
Commitments and contingencies
 
Shareholders’ equity   
Common stock1,623
 1,605
Retained earnings1,621
 1,536
Total shareholders' equity3,244
 3,141
Total liabilities and shareholders’ equity$9,541
 $9,104


37

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholders’
Equity
Common
Stock
 
Retained
Earnings
 
Total
Shareholders’
Equity
Balance, December 31, 2016$1,421
 $1,427
 $2,848
Balance, December 31, 2017$1,605
 $1,536
 $3,141
Net income—
 231
 231
—
 242
 242
Common stock dividends—
 (148) (148)—
 (157) (157)
Contributions from parent77
 —
 77
18
 —
 18
Balance, September 30, 2017$1,498

$1,510

$3,008
Balance, September 30, 2018$1,623

$1,621

$3,244

See the Combined Notes to Consolidated Financial Statements


38


PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Successor

  
Predecessor

Three Months Ended  
 September 30,		 Nine Months Ended September 30, March 24 to September 30,  January 1 to March 23,Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2017 2016 2017 2016  20162018 2017 2018 2017
Operating revenues                 
Electric operating revenues$1,280
 $1,366
 $3,417
 $2,485
  $1,096
$1,340
 $1,278
 $3,541
 $3,376
Natural gas operating revenues18
 17
 105
 46
  57
23
 18
 129
 105
Revenues from alternative revenue programs(5) 2
 7
 41
Operating revenues from affiliates12
 11
 35
 34
  —
3
 12
 11
 35
Total operating revenues1,310
 1,394
 3,557
 2,565
  1,153
1,361
 1,310
 3,688
 3,557
Operating expenses                 
Purchased power354
 370
 901
 658
  471
415
 354
 1,077
 901
Purchased fuel7
 6
 46
 17
  26
12
 7
 65
 46
Purchased power and fuel from affiliates112
 207
 371
 362
  —
82
 112
 268
 371
Operating and maintenance214
 200
 666
 870
  294
261
 214
 751
 666
Operating and maintenance from affiliates37
 26
 108
 51
  —
31
 37
 106
 108
Depreciation and amortization179
 182
 511
 355
  152
Depreciation, amortization and accretion192
 179
 555
 511
Taxes other than income122
 124
 344
 248
  105
123
 122
 343
 344
Total operating expenses1,025
 1,115
 2,947
 2,561
  1,048
1,116
 1,025
 3,165
 2,947
Gain on sales of assets—
 —
 1
 —
  —
—
 —
 —
 1
Operating income285
 279

 611
 4

 105
245
 285

523
 611
Other income and (deductions)                 
Interest expense, net(62) (64) (183) (135)  (65)(65) (62) (193) (183)
Other, net13
 19
 40
 31
  (4)11
 13
 33
 40
Total other income and (deductions)(49) (45) (143) (104)  (69)(54) (49) (160) (143)
Income (loss) before income taxes236
 234
 468
 (100)  36
Income before income taxes191
 236
 363
 468
Income taxes83
 68
 109
 (9)  17
4
 83
 28
 109
Net income (loss)$153
 $166
 $359
 $(91)  $19
Comprehensive income (loss), net of income taxes          
Net income (loss)$153
 $166
 $359
 $(91)  $19
Other comprehensive income, net of income taxes          
Pension and non-pension postretirement benefit plans:  
       
Actuarial loss reclassified to periodic cost—
 —
 —
 —
  1
Other comprehensive income—
 —
 —
 —
  1
Comprehensive income (loss)$153
 $166
 $359
 $(91)  $20
Equity in earnings of unconsolidated affiliate—
 —
 1
 —
Net income$187
 $153
 $336
 $359
Comprehensive income$187
 $153
 $336
 $359

See the Combined Notes to Consolidated Financial Statements

39

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Successor  Predecessor
Nine Months Ended September 30, March 24 to September 30,  January 1 to March 23,Nine Months Ended
September 30,
(In millions)2017 2016  20162018 2017
Cash flows from operating activities  
     
Net income (loss)$359
 $(91)  $19
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:      
Net income$336
 $359
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization511
 355
  152
555
 511
Deferred income taxes and amortization of investment tax credits190
 237
  19
50
 190
Net fair value changes related to derivatives—
 —
  18
Other non-cash operating activities66
 441
  46
109
 66
Changes in assets and liabilities:         
Accounts receivable(42) (94)  (28)(89) (42)
Receivables from and payables to affiliates, net(13) 39
  —
10
 (13)
Inventories(29) —
  (4)—
 (29)
Accounts payable and accrued expenses(49) (23)  42
115
 (49)
Income taxes82
 (57)  12
(31) 82
Pension and non-pension postretirement benefit contributions(74) (13)  (4)(66) (74)
Other assets and liabilities(204) (248)  (8)(144) (206)
Net cash flows provided by operating activities797
 546
  264
845
 795
Cash flows from investing activities         
Capital expenditures(995) (624)  (273)(988) (995)
Proceeds from sales of long-lived assets1
 19
  —
—
 1
Changes in restricted cash(1) (39)  3
Purchases of investments—
 —
  (68)
Other investing activities4
 13
  (5)2
 4
Net cash flows used in investing activities(991)
(631)
 (343)(986)
(990)
Cash flows from financing activities         
Changes in short-term borrowings96
 (520)  (121)(141) 96
Proceeds from short-term borrowings with maturities greater than 90 days—
 —
  500
125
 —
Repayments of short-term borrowings with maturities greater than 90 days(500) (300)  —
—
 (500)
Issuance of long-term debt202
 2
  —
300
 202
Retirement of long-term debt(127) (29)  (11)(33) (127)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation—
 —
  2
Distributions to member(267) (174)  —
(232) (267)
Contributions from member758
 1,088
  —
Contributions from parent237
 758
Change in Exelon intercompany money pool1
 1
  —
10
 1
Other financing activities(2) (3)  2
(6) (2)
Net cash flows provided by financing activities161
 65
  372
260
 161
(Decrease) Increase in cash and cash equivalents(33) (20)  293
Cash and cash equivalents at beginning of period170
 319
  26
Cash and cash equivalents at end of period$137
 $299
  $319
Increase (decrease) in cash, cash equivalents and restricted cash119
 (34)
Cash, cash equivalents and restricted cash at beginning of period95
 236
Cash, cash equivalents and restricted cash at end of period$214
 $202

See the Combined Notes to Consolidated Financial Statements

40

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
Successor
(In millions)September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
ASSETS      
Current assets      
Cash and cash equivalents$137
 $170
$153
 $30
Restricted cash and cash equivalents43
 43
42
 42
Accounts receivable, net      
Customer490
 496
500
 486
Other209
 283
266
 206
Inventories, net      
Gas held in storage9
 6
9
 7
Materials and supplies141
 116
149
 151
Regulatory assets568
 653
521
 554
Other59
 71
60
 75
Total current assets1,656

1,838
1,700

1,551
Property, plant and equipment, net12,219
 11,598
13,167
 12,498
Deferred debits and other assets      
Regulatory assets2,692
 2,851
2,374
 2,493
Investments132
 133
133
 132
Goodwill4,005
 4,005
4,005
 4,005
Long-term note receivable4
 4
—
 4
Prepaid pension asset510
 509
499
 490
Deferred income taxes6
 6
12
 4
Other77
 81
67
 70
Total deferred debits and other assets7,426

7,589
7,090

7,198
Total assets(a)
$21,301

$21,025
$21,957

$21,247

See the Combined Notes to Consolidated Financial Statements

41

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
Successor
(In millions)September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
LIABILITIES AND MEMBER'S EQUITY      
Current liabilities      
Short-term borrowings$118
 $522
$334
 $350
Long-term debt due within one year159
 253
117
 396
Accounts payable397
 458
505
 348
Accrued expenses294
 272
269
 261
Payables to affiliates79
 94
102
 90
Borrowings from Exelon intercompany money pool10
 —
Unamortized energy contract liabilities231
 335
125
 188
Borrowings from Exelon intercompany money pool1
 —
Customer deposits119
 123
113
 119
Merger related obligation53
 101
38
 42
Regulatory liabilities65
 79
99
 56
Other41
 47
57
 81
Total current liabilities1,557
 2,284
1,769
 1,931
Long-term debt5,771
 5,645
5,972
 5,478
Deferred credits and other liabilities      
Regulatory liabilities146
 158
Deferred income taxes and unamortized investment tax credits4,003
 3,775
2,243
 2,070
Asset retirement obligations17
 14
53
 16
Non-pension postretirement benefit obligations128
 134
102
 105
Regulatory liabilities1,783
 1,872
Unamortized energy contract liabilities599
 750
474
 561
Other214
 249
395
 389
Total deferred credits and other liabilities5,107
 5,080
5,050
 5,013
Total liabilities(a)
12,435
 13,009
12,791
 12,422
Commitments and contingencies   
 
Member's equity      
Membership interest8,835
 8,077
9,072
 8,835
Undistributed earnings (losses)31
 (61)94
 (10)
Total member's equity8,866

8,016
9,166

8,825
Total liabilities and member's equity$21,301

$21,025
$21,957

$21,247
__________
(a)PHI’s consolidated total assets include $43$36 million and $49$41 million at September 30, 20172018 and December 31, 2016,2017, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $112$78 million and $143$102 million at September 30, 20172018 and December 31, 2016,2017, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 3 -— Variable Interest Entities.Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

42

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Unaudited)
(In millions)Membership Interest Undistributed Earnings (Losses) Member's Equity
Successor     
Balance, December 31, 2016$8,077
 $(61) $8,016
Net income—
 359
 359
Distribution to member—
 (267) (267)
Contribution from member751
 —
 751
Allocation of tax benefit from member7
 —
 7
Balance, September 30, 2017$8,835
 $31
 $8,866
(In millions)Membership Interest Undistributed Earnings (Losses) Member's Equity
Balance, December 31, 2017$8,835
 $(10) $8,825
Net income—
 336
 336
Distributions to member—
 (232) (232)
Contributions from parent237
 —
 237
Balance, September 30, 2018$9,072
 $94
 $9,166

See the Combined Notes to Consolidated Financial Statements

43


POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Ended September 30,
Nine Months Ended September 30,Three Months Ended September 30,
Nine Months Ended September 30,
(In millions)2017
2016
2017
20162018
2017
2018
2017
Operating revenues              
Electric operating revenues$603
 $634
 $1,645
 $1,692
$630
 $600
 $1,697
 $1,622
Revenues from alternative revenue programs(4) 3
 6
 23
Operating revenues from affiliates1
 1
 4
 3
2
 1
 5
 4
Total operating revenues604
 635
 1,649
 1,695
628
 604
 1,708
 1,649
Operating expenses              
Purchased power111
 84
 268
 340
131
 111
 354
 268
Purchased power from affiliates57
 129
 210
 223
46
 57
 143
 210
Operating and maintenance89
 100
 296
 488
84
 89
 216
 296
Operating and maintenance from affiliates14
 9
 40
 20
52
 14
 167
 40
Depreciation and amortization82
 76
 242
 221
99
 82
 286
 242
Taxes other than income102
 105
 282
 287
104
 102
 288
 282
Total operating expenses455
 503
 1,338
 1,579
516
 455
 1,454
 1,338
Gain on sales of assets—
 —
 1
 8
—
 —
 —
 1
Operating income149
 132
 312
 124
112
 149
 254
 312
Other income and (deductions)              
Interest expense, net(31) (30) (89) (98)(32) (31) (96) (89)
Other, net7
 12
 22
 28
7
 7
 23
 22
Total other income and (deductions)(24) (18) (67) (70)(25) (24) (73) (67)
Income before income taxes125
 114
 245
 54
87
 125
 181
 245
Income taxes38
 35
 57
 34
(2) 38
 7
 57
Net income$87
 $79
 $188
 $20
$89
 $87
 $174
 $188
Comprehensive income$87
 $79
 $188
 $20
$89
 $87
 $174
 $188

See the Combined Notes to Consolidated Financial Statements

44

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended 
 September 30,		Nine Months Ended
September 30,
(In millions)2017 20162018 2017
Cash flows from operating activities      
Net income$188
 $20
$174
 $188
Adjustments to reconcile net income to net cash flows provided by operating activities:
 
   
Depreciation and amortization242
 221
286
 242
Deferred income taxes and amortization of investment tax credits90
 96
(5) 90
Other non-cash operating activities8
 168
42
 8
Changes in assets and liabilities:
 

 
Accounts receivable(43) (105)(36) (43)
Receivables from and payables to affiliates, net(10) 44
(9) (10)
Inventories(15) 3
6
 (15)
Accounts payable and accrued expenses(24) 7
104
 (24)
Income taxes80
 139
(18) 80
Pension and non-pension postretirement benefit contributions(69) (6)(11) (69)
Other assets and liabilities(99) (83)(137) (99)
Net cash flows provided by operating activities348
 504
396
 348
Cash flows from investing activities
 
   
Capital expenditures(439) (392)(475) (439)
Proceeds from sale of long-lived asset1
 12
Purchases of investments—
 (32)
Changes in restricted cash(1) (31)
Proceeds from sales of long-lived assets—
 1
Other investing activities—
 8
3
 —
Net cash flows used in investing activities(439) (435)(472) (438)
Cash flows from financing activities
 
   
Changes in short-term borrowings(23) (64)38
 (23)
Issuance of long-term debt202
 2
100
 202
Retirement of long-term debt(7) (5)(8) (7)
Dividends paid on common stock(133) (92)(128) (133)
Contribution from parent161
 187
Contributions from parent85
 161
Other financing activities(1) —
(4) (1)
Net cash flows provided by financing activities199
 28
83
 199
Increase in cash and cash equivalents108
 97
Cash and cash equivalents at beginning of period9
 5
Cash and cash equivalents at end of period$117
 $102
Increase in cash, cash equivalents and restricted cash7
 109
Cash, cash equivalents and restricted cash at beginning of period40
 42
Cash, cash equivalents and restricted cash at end of period$47
 $151

See the Combined Notes to Consolidated Financial Statements


45

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)

(In millions)September 30, 2017
December 31, 2016September 30, 2018
December 31, 2017
ASSETS      
Current assets      
Cash and cash equivalents$117
 $9
$12
 $5
Restricted cash and cash equivalents34
 33
35
 35
Accounts receivable, net      
Customer265
 235
235
 250
Other92
 150
102
 87
Inventories, net78
 63
81
 87
Regulatory assets181
 162
284
 213
Other10
 32
9
 33
Total current assets777

684
758

710
Property, plant and equipment, net5,866
 5,571
6,337
 6,001
Deferred debits and other assets      
Regulatory assets699
 690
662
 678
Investments102
 102
105
 102
Prepaid pension asset327
 282
318
 322
Other4
 6
19
 19
Total deferred debits and other assets1,132

1,080
1,104

1,121
Total assets$7,775

$7,335
$8,199

$7,832

See the Combined Notes to Consolidated Financial Statements

46

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)

(In millions)September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Short-term borrowings$—
 $23
$64
 $26
Long-term debt due within one year19
 16
14
 19
Accounts payable168
 209
234
 139
Accrued expenses153
 113
141
 137
Payables to affiliates64
 74
70
 74
Customer deposits53
 53
53
 54
Regulatory liabilities5
 11
5
 3
Merger related obligation42
 68
38
 42
Current portion of DC PLUG obligation30
 28
Other20
 29
9
 28
Total current liabilities524

596
658

550
Long-term debt2,527
 2,333
2,611
 2,521
Deferred credits and other liabilities      
Regulatory liabilities21
 20
Deferred income taxes and unamortized investment tax credits2,024
 1,910
1,139
 1,063
Non-pension postretirement benefit obligations37
 43
31
 36
Regulatory liabilities759
 829
Other126
 133
337
 300
Total deferred credits and other liabilities2,208

2,106
2,266

2,228
Total liabilities5,259

5,035
5,535

5,299
Commitments and contingencies   
 
Shareholder's equity      
Common stock1,470
 1,309
1,555
 1,470
Retained earnings1,046
 991
1,109
 1,063
Total shareholder's equity2,516
 2,300
2,664
 2,533
Total liabilities and shareholder's equity$7,775
 $7,335
$8,199
 $7,832

See the Combined Notes to Consolidated Financial Statements



47

POTOMAC ELECTRIC POWER COMPANY
STATEMENT OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)

(In millions)Common Stock Retained Earnings Total Shareholder's EquityCommon Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2016$1,309
 $991
 $2,300
Balance, December 31, 2017$1,470
 $1,063
 $2,533
Net income—
 188
 188
—
 174
 174
Common stock dividends—
 (133) (133)—
 (128) (128)
Contributions from parent161
 —
 161
85
 —
 85
Balance, September 30, 2017$1,470

$1,046

$2,516
Balance, September 30, 2018$1,555

$1,109

$2,664

See the Combined Notes to Consolidated Financial Statements



48



DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Ended September 30,
Nine Months Ended September 30,Three Months Ended September 30,
Nine Months Ended September 30,
(In millions)2017
2016
2017
20162018
2017
2018
2017
Operating revenues              
Electric operating revenues$307
 $312
 $860
 $866
$302
 $308
 $861
 $851
Natural gas operating revenues18
 17
 105
 102
24
 18
 129
 105
Revenues from alternative revenue programs—
 (1) 5
 9
Operating revenues from affiliates2
 2
 6
 6
2
 2
 6
 6
Total operating revenues327

331

971

974
328

327

1,001

971
Operating expenses              
Purchased power75
 81
 215
 297
96
 75
 258
 215
Purchased fuel7
 6
 46
 41
11
 7
 64
 46
Purchased power from affiliate47
 63
 138
 110
26
 47
 103
 138
Operating and maintenance71
 50
 204
 327
44
 71
 137
 204
Operating and maintenance from affiliates8
 5
 23
 11
38
 8
 119
 23
Depreciation and amortization45
 44
 124
 120
47
 45
 135
 124
Taxes other than income15
 14
 43
 42
15
 15
 43
 43
Total operating expenses268

263

793

948
277

268

859

793
Gain on sale of asset—
 4
 —
 4
Operating income59

72

178

30
51

59

142

178
Other income and (deductions)              
Interest expense, net(13) (12) (38) (37)(15) (13) (42) (38)
Other, net4
 3
 10
 9
2
 4
 7
 10
Total other income and (deductions)(9)
(9)
(28)
(28)(13)
(9)
(35)
(28)
Income before income taxes50
 63
 150
 2
38
 50
 107
 150
Income taxes19
 19
 43
 18
5
 19
 17
 43
Net income (loss)$31

$44

$107

$(16)
Comprehensive income (loss)$31
 $44
 $107
 $(16)
Net income$33

$31

$90

$107
Comprehensive income$33
 $31
 $90
 $107

See the Combined Notes to Consolidated Financial Statements

49

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months Ended 
 September 30,		Nine Months Ended
September 30,
(In millions)2017
20162018
2017
Cash flows from operating activities      
Net income (loss)$107
 $(16)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:   
Net income$90
 $107
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization124
 120
135
 124
Deferred income taxes and amortization of investment tax credits61
 69
24
 61
Other non-cash operating activities6
 99
16
 6
Changes in assets and liabilities:      
Accounts receivable7
 8
13
 7
Receivables from and payables to affiliates, net—
 12
(14) —
Inventories(6) —
(3) (6)
Accounts payable and accrued expenses—
 (8)18
 —
Collateral received—
 1
Income Taxes33
 52
Income taxes—
 33
Other assets and liabilities(40) (70)13
 (40)
Net cash flows provided by operating activities292

267
292

292
Cash flows from investing activities      
Capital expenditures(294) (260)(254) (294)
Proceeds from sale of long-lived asset
—
 4
Other investing activities1
 2
1
 1
Net cash flows used in investing activities(293)
(254)(253)
(293)
Cash flows from financing activities      
Changes in short-term borrowings54
 (88)(216) 54
Issuance of long-term debt200
 —
Retirement of long-term debt(14) —
(4) (14)
Dividends paid on common stock(82) (39)(58) (82)
Contribution from parent—
 113
Net cash flows used in financing activities(42)
(14)
Decrease in cash and cash equivalents(43) (1)
Cash and cash equivalents at beginning of period46
 5
Cash and cash equivalents at end of period$3

$4
Contributions from parent150
 —
Other financing activities(3) —
Net cash flows provided by (used in) financing activities69

(42)
Increase (decrease) in cash, cash equivalents and restricted cash108
 (43)
Cash, cash equivalents and restricted cash at beginning of period2
 46
Cash, cash equivalents and restricted cash at end of period$110

$3

See the Combined Notes to Consolidated Financial Statements

50

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)

(In millions)September 30, 2017 December 31, 2016
ASSETS   
Current assets   
Cash and cash equivalents$3
 $46
Accounts receivable, net   
Customer118
 136
Other36
 63
Receivables from affiliates—
 3
Inventories, net   
Gas held in storage9
 7
Materials and supplies35
 32
Regulatory assets69
 59
Other16
 24
Total current assets286

370
Property, plant and equipment, net3,480
 3,273
Deferred debits and other assets   
Regulatory assets300
 289
Goodwill8
 8
Prepaid pension asset197
 206
Other5
 7
Total deferred debits and other assets510

510
Total assets$4,276

$4,153

See the Combined Notes to Consolidated Financial Statements

51

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2017 December 31, 2016
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Short-term borrowings$54
 $—
Long-term debt due within one year109
 119
Accounts payable95
 88
Accrued expenses52
 36
Payables to affiliates35
 38
Customer deposits35
 36
Regulatory liabilities42
 43
Merger related obligation3
 13
Other7
 8
Total current liabilities432
 381
Long-term debt1,217
 1,221
Deferred credits and other liabilities   
Regulatory liabilities86
 97
Deferred income taxes and unamortized investment tax credits1,125
 1,056
Non-pension postretirement benefit obligations17
 19
Other48
 53
Total deferred credits and other liabilities1,276

1,225
Total liabilities2,925

2,827
Commitments and contingencies   
Shareholder's equity   
Common stock764
 764
Retained earnings587
 562
Total shareholder's equity1,351

1,326
Total liabilities and shareholder's equity$4,276

$4,153
(In millions)September 30, 2018 December 31, 2017
ASSETS   
Current assets   
Cash and cash equivalents$110
 $2
Accounts receivable, net   
Customer121
 146
Other53
 38
Inventories, net   
Gas held in storage9
 7
Materials and supplies37
 36
Regulatory assets66
 69
Other18
 27
Total current assets414

325
Property, plant and equipment, net3,748
 3,579
Deferred debits and other assets   
Regulatory assets235
 245
Goodwill8
 8
Prepaid pension asset188
 193
Other8
 7
Total deferred debits and other assets439

453
Total assets$4,601

$4,357

See the Combined Notes to Consolidated Financial Statements

52

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2018 December 31, 2017
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Short-term borrowings$—
 $216
Long-term debt due within one year79
 83
Accounts payable104
 82
Accrued expenses52
 35
Payables to affiliates30
 46
Customer deposits35
 35
Regulatory liabilities67
 42
Other6
 8
Total current liabilities373
 547
Long-term debt1,415
 1,217
Deferred credits and other liabilities   
Regulatory liabilities587
 593
Deferred income taxes and unamortized investment tax credits645
 603
Non-pension postretirement benefit obligations15
 14
Other49
 48
Total deferred credits and other liabilities1,296

1,258
Total liabilities3,084

3,022
Commitments and contingencies
 
Shareholder's equity   
Common stock914
 764
Retained earnings603
 571
Total shareholder's equity1,517

1,335
Total liabilities and shareholder's equity$4,601

$4,357

DELMARVA POWER & LIGHT COMPANY
STATEMENT OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)

(In millions)Common Stock Retained Earnings Total Shareholder's EquityCommon Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2016$764
 $562
 $1,326
Balance, December 31, 2017$764
 $571
 $1,335
Net income—
 107
 107
—
 90
 90
Common stock dividends—
 (82) (82)—
 (58) (58)
Balance, September 30, 2017$764
 $587
 $1,351
Contributions from parent150
 —
 150
Balance, September 30, 2018$914
 $603
 $1,517

See the Combined Notes to Consolidated Financial Statements



53



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended September 30, Nine Months Ended September 30,Three Months Ended September 30, Nine Months Ended
September 30,
(In millions)2017 2016 2017 20162018 2017 2018 2017
Operating revenues              
Electric operating revenues$370
 $420
 $913
 $979
$406
 $370
 $983
 $904
Revenues from alternative revenue programs(1) —
 (4) 9
Operating revenues from affiliates—
 1
 2
 3
1
 —
 2
 2
Total operating revenues370
 421
 915
 982
406
 370
 981
 915
Operating expenses              
Purchased power169
 206
 418
 491
188
 169
 465
 418
Purchased power from affiliates7
 15
 24
 29
10
 7
 21
 24
Operating and maintenance66
 62
 205
 336
52
 66
 146
 205
Operating and maintenance from affiliates6
 5
 20
 10
33
 6
 104
 20
Depreciation and amortization41
 49
 113
 130
38
 41
 107
 113
Taxes other than income2
 1
 6
 6
1
 2
 4
 6
Total operating expenses291
 338
 786
 1,002
322
 291
 847
 786
Gain on sale of assets—
 —
 —
 1
Operating income (loss)79

83
 129

(19)
Operating income84

79
 134

129
Other income and (deductions)              
Interest expense, net(15) (15) (46) (47)(16) (15) (48) (46)
Other, net1
 2
 6
 8
1
 1
 2
 6
Total other income and (deductions)(14) (13) (40) (39)(15) (14) (46) (40)
Income (loss) before income taxes65
 70
 89
 (58)
Income before income taxes69
 65
 88
 89
Income taxes24
 23
 12
 (8)8
 24
 12
 12
Net income (loss)$41

$47

$77

$(50)
Comprehensive income (loss)$41
 $47
 $77
 $(50)
Net income$61

$41

$76

$77
Comprehensive income$61
 $41
 $76
 $77

See the Combined Notes to Consolidated Financial Statements

54

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months Ended 
 September 30,		Nine Months Ended
September 30,
(In millions)2017
20162018
2017
Cash flows from operating activities      
Net income (loss)$77
 $(50)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:   
Net income$76
 $77
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization113
 130
107
 113
Deferred income taxes and amortization of investment tax credits28
 14
24
 28
Other non-cash operating activities21
 138
24
 21
Changes in assets and liabilities:      
Accounts receivable(7) (32)(66) (7)
Receivables from and payables to affiliates, net(5) 9
(3) (5)
Inventories(7) (1)(2) (7)
Accounts payable and accrued expenses9
 10
21
 9
Income taxes(9) 184
(3) (9)
Pension and non-pension postretirement benefit contributions(6) —
Other assets and liabilities(62) (87)(12) (62)
Net cash flows provided by operating activities158
 315
160
 158
Cash flows from investing activities      
Capital expenditures(242) (227)(247) (242)
Proceeds from sale of long-lived asset
—
 2
Changes in restricted cash1
 (4)
Other investing activities—
 2
(1) —
Net cash flows used in investing activities(241) (227)(248) (242)
Cash flows from financing activities      
Changes in short-term borrowings65
 (5)37
 65
Proceeds from short-term borrowings with maturities greater than 90 days125
 —
Retirement of long-term debt(25) (35)(22) (25)
Dividends paid on common stock(53) (24)(46) (53)
Contribution from parent—
 139
Other financing activities—
 (1)
Net cash flows (used in) provided by financing activities(13) 74
(Decrease) Increase in cash and cash equivalents(96) 162
Cash and cash equivalents at beginning of period101
 3
Cash and cash equivalents at end of period$5

$165
Net cash flows provided by (used in) financing activities94
 (13)
Increase (decrease) in cash, cash equivalents and restricted cash6
 (97)
Cash, cash equivalents and restricted cash at beginning of period31
 133
Cash, cash equivalents and restricted cash at end of period$37

$36

See the Combined Notes to Consolidated Financial Statements


55

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2018 December 31, 2017
ASSETS   
Current assets   
Cash and cash equivalents$11
 $2
Restricted cash and cash equivalents7
 6
Accounts receivable, net   
Customer144
 92
Other59
 56
Inventories, net31
 29
Regulatory assets44
 71
Other21
 2
Total current assets317
 258
Property, plant and equipment, net2,883
 2,706
Deferred debits and other assets   
Regulatory assets383
 359
Long-term note receivable—
 4
Prepaid pension asset70
 73
Other41
 45
Total deferred debits and other assets494
 481
Total assets(a)
$3,694
 $3,445

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

(In millions)September 30, 2017 December 31, 2016
ASSETS   
Current assets   
Cash and cash equivalents$5
 $101
Restricted cash and cash equivalents9
 9
Accounts receivable, net   
Customer107
 125
Other54
 44
Inventories, net29
 22
Prepaid utility taxes15
 —
Regulatory assets87
 96
Other3
 2
Total current assets309
 399
Property, plant and equipment, net2,662
 2,521
Deferred debits and other assets   
Regulatory assets417
 405
Long-term note receivable4
 4
Prepaid pension asset76
 84
Other42
 44
Total deferred debits and other assets539
 537
Total assets(a)
$3,510
 $3,457

See the Combined Notes to Consolidated Financial Statements

56

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

(In millions)September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Short-term borrowings$65
 $—
$270
 $108
Long-term debt due within one year32
 35
22
 281
Accounts payable122
 132
149
 118
Accrued expenses39
 38
38
 33
Payables to affiliates24
 29
25
 29
Customer deposits31
 33
26
 31
Regulatory liabilities18
 25
27
 11
Merger related obligation8
 20
Other6
 8
9
 8
Total current liabilities345
 320
566
 619
Long-term debt1,098
 1,120
1,078
 840
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits951
 917
534
 493
Non-pension postretirement benefit obligations33
 34
16
 14
Regulatory liabilities401
 411
Other25
 32
26
 25
Total deferred credits and other liabilities1,009
 983
977
 943
Total liabilities(a)
2,452
 2,423
2,621
 2,402
Commitments and contingencies   
 
Shareholder's equity      
Common stock912
 912
912
 912
Retained earnings146
 122
161
 131
Total shareholder's equity1,058

1,034
1,073

1,043
Total liabilities and shareholder's equity$3,510

$3,457
$3,694

$3,445
__________
(a)ACE’s consolidated total assets include $31$26 million and $32$29 million at September 30, 20172018 and December 31, 2016,2017, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $100$68 million and $126$90 million at September 30, 20172018 and December 31, 2016,2017, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 3 -— Variable Interest Entities.Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

57

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)

(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2016$912
 $122
 $1,034
Net income—
 77
 77
Common stock dividends—
 (53) (53)
Balance, September 30, 2017$912

$146
 $1,058

See the Combined Notes to Consolidated Financial Statements

58
Table of Contents
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2017$912
 $131
 $1,043
Net income—
 76
 76
Common stock dividends—
 (46) (46)
Balance, September 30, 2018$912

$161
 $1,073
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:
Applicable Notes
Registrant123456789101112131415161718192012345678910111213141516171819
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 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

1. Basis of PresentationSignificant 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, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions.
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.

59
Table of Contents
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.
Name of RegistrantBusinessService Territories
Exelon Generation
Company, LLC		Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy and other energy-related products and services.Six reportable segments: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions
Commonwealth Edison CompanyPurchase and regulated retail sale of electricityNorthern Illinois, including the City of Chicago
Transmission and distribution of electricity to retail customers
PECO Energy CompanyPurchase and regulated retail sale of electricity and natural gasSoutheastern Pennsylvania, including the City of Philadelphia (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customersPennsylvania counties surrounding the City of Philadelphia (natural gas)
Baltimore Gas and Electric CompanyPurchase and regulated retail sale of electricity and natural gasCentral Maryland, including the City of Baltimore (electricity and natural gas)
Transmission and distribution of electricity and distribution of natural gas to retail customers
Pepco Holdings LLCUtility services holding company engaged, through its reportable segments Pepco, DPL and ACEService Territories of Pepco, DPL and ACE
Potomac Electric 
Power Company		Purchase and regulated retail sale of electricityDistrict of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland
Transmission and distribution of electricity to retail customers
Delmarva Power &
Light Company
Purchase and regulated retail sale of electricity and natural gasPortions of Delaware and Maryland (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customersPortions of New Castle County, Delaware (natural gas)
Atlantic City Electric CompanyPurchase and regulated retail sale of electricityPortions of Southern New Jersey
Transmission and distribution of electricity to retail customers
Basis of Presentation (All Registrants)
As a result of 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 that identifiable 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 related to Exelon now also apply to PHI, Pepco, DPL and ACE, unless otherwise noted.
Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
The accompanying consolidated financial statements as of September 30, 20172018 and 20162017 and for the three and nine months then ended are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 20162017 revised Consolidated Balance Sheets were derived from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2017.2018. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.

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

Prior Period Adjustments and Reclassifications (All Registrants)
Certain prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows, Consolidated Balance Sheets and Consolidated Statements of Changes in Shareholders' Equity have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.
Beginning on January 1, 2018, Exelon adopted the following new accounting standards requiring reclassification or adjustments to previously reported information as follows:
Statement of Cash Flows: Classification of Restricted Cash. The Registrants applied the new guidance using the full retrospective method and, accordingly, have recasted the presentation of restricted cash in their Consolidated Statements of Cash Flows in the prior periods presented. See Note 18 — Supplemental Financial Information for additional information.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.  Exelon early adopted and retrospectively applied the new guidance to when the effects of the TCJA were recognized and, accordingly, recasted its December 31, 2017 AOCI and retained earnings in its Consolidated Balance Sheet and Consolidated Statement of Changes in Shareholders' Equity.  Exelon's accounting policy is to release the stranded tax effects from AOCI related to its pension and OPEB plans under a portfolio (or aggregate) approach as an entire pension or OPEB plan is liquidated or terminated. See Note 2 — New Accounting Standards for additional information.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. Exelon applied this guidance retrospectively for the presentation of the service and other non-service costs components of net benefit cost and, accordingly, have recasted those amounts, which were not material, in its Consolidated Statement of Operations and Comprehensive Income in prior periods presented. As part of the adoption, Exelon elected the practical expedient that permits an employer to use the amounts disclosed in its pension and other postretirement benefit plan note for the comparative periods as the estimation basis for applying the retrospective presentation requirements. See Note 14 — Retirement Benefits for additional information.
Revenue from Contracts with Customers. The Registrants applied the new guidance using the full retrospective method and, accordingly, have recasted certain amounts in their Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows, Consolidated Balance Sheets, Consolidated Statements of Changes in Shareholders' Equity and Combined Notes to Consolidated Financial Statements in the prior periods presented. The amounts recasted in the Registrants' Consolidated Statements of Operations and Comprehensive Income are shown in the table below. The amounts recasted in the Registrants’ Consolidated Statements of Cash Flows, Consolidated Balance Sheets, Consolidated Statements of Changes in Shareholders' Equity and Combined Notes to Consolidated Financial Statements were not material.  See Note 5 — Revenue from Contracts with Customers for additional information.

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

Three Months Ended September 30, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating Revenues - As reported                 
Competitive business revenues$4,456
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Rate-regulated utility revenues4,313
 —
 —
 —
 —
 —
 —
 —
 —
Operating revenues—
 4,455
 —
 —
 —
 —
 —
 —
 —
Electric operating revenues—
 —
 1,568
 660
 657
 1,280
 603
 307
 370
Natural gas operating revenues—
 —
 —
 53
 78
 18
 —
 18
 —
Operating revenues from affiliates—
 296
 3
 2
 3
 12
 1
 2
 —
Total operating revenues$8,769
 $4,751
 $1,571
 $715
 $738
 $1,310
 $604
 $327
 $370
                  
Operating Revenues - Adjustments                 
Competitive business revenues$(1) $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Rate-regulated utility revenues(54) —
 —
 —
 —
 —
 —
 —
 —
Operating revenues—
 (1) —
 —
 —
 —
 —
 —
 —
Electric operating revenues—
 —
 (16) —
 (31) (2) (3) 1
 —
Natural gas operating revenues—
 —
 —
 —
 (5) —
 —
 —
 —
Revenues from alternative revenue programs54
 —
 16
 —
 36
 2
 3
 (1) —
Operating revenues from affiliates—
 —
 —
 —
 —
 —
 —
 —
 —
Total operating revenues$(1) $(1) $—
 $—
 $—
 $—
 $—
 $—
 $—
                  
Operating Revenues - Retrospective application                 
Competitive business revenues$4,455
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Rate-regulated utility revenues4,259
 —
 —
 —
 —
 —
 —
 —
 —
Operating revenues—
 4,454
 —
 —
 —
 —
 —
 —
 —
Electric operating revenues—
 —
 1,552
 660
 626
 1,278
 600
 308
 370
Natural gas operating revenues—
 —
 —
 53
 73
 18
 —
 18
 —
Revenues from alternative revenue programs54
 —
 16
 —
 36
 2
 3
 (1) —
Operating revenues from affiliates—
 296
 3
 2
 3
 12
 1
 2
 —
Total operating revenues$8,768
 $4,750
 $1,571
 $715
 $738
 $1,310
 $604
 $327
 $370

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

Nine Months Ended September 30, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating Revenues - As reported                 
Competitive business revenues$12,924
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Rate-regulated utility revenues12,225
 —
 —
 —
 —
 —
 —
 —
 —
Operating revenues—
 12,918
 —
 —
 —
 —
 —
 —
 —
Electric operating revenues—
 —
 4,215
 1,798
 1,890
 3,417
 1,645
 860
 913
Natural gas operating revenues—
 —
 —
 338
 461
 105
 —
 105
 —
Operating revenues from affiliates—
 894
 12
 5
 12
 35
 4
 6
 2
Total operating revenues$25,149
 $13,812
 $4,227
 $2,141
 $2,363
 $3,557
 $1,649
 $971
 $915
                  
Operating Revenues - Adjustments                 
Competitive business revenues$31
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Rate-regulated utility revenues(191) —
 —
 —
 —
 —
 —
 —
 —
Operating revenues—
 31
 —
 —
 —
 —
 —
 —
 —
Electric operating revenues—
 —
 (48) —
 (79) (41) (23) (9) (9)
Natural gas operating revenues—
 —
 —
 —
 (23) —
 —
 —
 —
Revenues from alternative revenue programs191
 —
 48
 —
 102
 41
 23
 9
 9
Operating revenues from affiliates—
 —
 —
 —
 —
 —
 —
 —
 —
Total operating revenues$31
 $31
 $—
 $—
 $—
 $—
 $—
 $—
 $—
                  
Operating Revenues - Retrospective application                 
Competitive business revenues$12,955
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Rate-regulated utility revenues12,034
 —
 —
 —
 —
 —
 —
 —
 —
Operating revenues—
 12,949
 —
 —
 —
 —
 —
 —
 —
Electric operating revenues—
 —
 4,167
 1,798
 1,811
 3,376
 1,622
 851
 904
Natural gas operating revenues—
 —
 —
 338
 438
 105
 —
 105
 —
Revenues from alternative revenue programs191
 —
 48
 —
 102
 41
 23
 9
 9
Operating revenues from affiliates—
 894
 12
 5
 12
 35
 4
 6
 2
Total operating revenues$25,180
 $13,843
 $4,227
 $2,141
 $2,363
 $3,557
 $1,649
 $971
 $915

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

Revenues (All Registrants)
Operating Revenues. The Registrants’ operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services, utility revenues from alternative revenue programs (ARP), and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and natural gas tariff sales, distribution and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. See Note 5 — Revenue from Contracts with Customers and Note 6 —Regulatory Matters for additional 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 sale or purchase position. In addition, capacity revenue and expense classification is based on the net sale or purchase position of the Registrants 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 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. See Note 6 — Regulatory Matters and Note 10 — Derivative Financial Instruments for additional information.
Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees that are levied by state or local governments on the sale or distribution of natural gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed directly on the Registrants. The Registrants do not recognize revenue or expense in their Consolidated Statements of Operations and Comprehensive Income when these taxes are imposed on the customer, such as sales taxes. However, when these taxes are imposed directly on the Registrants, such as gross receipts taxes or other surcharges or fees, the Registrants recognize revenue for the taxes collected from customers along with an offsetting expense. See Note 18 — 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.

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

2. New Accounting Standards (All Registrants)
New Accounting Standards Adopted: In 2018, the Registrants have adopted the following new authoritative accounting guidance issued by the FASB.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Issued February 2018): Provides an election for a reclassification from AOCI to Retained earnings to eliminate the stranded tax effects resulting from the TCJA. This standard is effective January 1, 2019, with early adoption permitted, and may be applied either in the period of adoption or retrospective to each period in which the effects of the TCJA were recognized. Exelon early adopted this standard during the first quarter 2018 and elected to apply the guidance retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million related to deferred income taxes associated with Exelon’s pension and OPEB obligations. There was no impact for Generation or the Utility Registrants.
See Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K for information on other new accounting standards issued and adopted as of January 1, 2018.
New Accounting Standards Issued and Not Yet Adopted:Adopted as of September 30, 2018: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements.statements as of September 30, 2018. 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 that 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 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. Exelon has not early adopted this standard.

60
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

The new standard replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method).
The Registrants have assessed the revenue recognition standard and are executing a detailed implementation plan in preparation for adoption on January 1, 2018. The Registrants have also actively participated 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. In coordination with the Industry Task Force, the Registrants have reached conclusions on the following key accounting issues:
The Utility Registrants’ tariff sale contracts, including those with lower credit quality customers, are generally deemed to be probable of collection under the guidance and, thus, the timing of revenue recognition will continue to be concurrent with the delivery of electricity or natural gas, consistent with current practice;
Consistent with current industry practice, revenues recognized from sales of bundled energy commodities (i.e., contracts involving the delivery of multiple energy commodities such as electricity, capacity, ancillary services, etc.) are generally expected to be recognized upon delivery to the customer in an amount based on the invoice price given that it corresponds directly with the value of the commodities transferred to the customer; and
Contributions in aid of construction are outside of the scope of the standard and, therefore, will continue to be accounted for as a reduction to Property, Plant, and Equipment.
The Registrants have also completed the following key activities in their implementation plan:
Evaluated existing contracts and revenue streams for potential changes in revenue recognition under the new guidance.  Based on these assessments, the Registrants have identified the following items that will be accounted for differently under the new revenue guidance as compared to current guidance:
Costs to acquire certain contracts (e.g., sales commissions associated with retail power contracts) will be deferred and amortized ratably over the term of the contract rather than being expensed as incurred; and
Variable consideration within certain contracts (e.g., performance bonuses) will be estimated and recognized as revenue over the term of the contract rather than being recognized when realized
Notwithstanding these identified changes, Exelon does not expect the new guidance will have a material impact on the amount and timing of revenue recognition;
Currently expect to apply the new guidance using the full retrospective method; and
Generation expects to disclose disaggregated revenue by operating segment and further differentiation by major products (i.e., electric power and gas) and the Utility Registrants expect to disclose disaggregated revenue by major customer class (i.e., residential and commercial & industrial) separately for electric and gas in the Combined Notes to Consolidated Financial Statements.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (Issued March 2017): The new standard will require significant changes to the accounting and presentation of pension and OPEB costs at the plan sponsor (i.e., Exelon) level. This guidance requires plan sponsors to report the service cost and other non-service cost components of net periodic pension cost and net periodic OPEB cost (together, net benefit cost) separately. Under current GAAP, net benefit cost is recorded as part of income from operations and the components are disclosed in the Retirement Benefits footnote. Service cost will be presented as part of income from operations and the other non-service cost components will be classified outside of income from operations on the Consolidated

61
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Statements of Operations and Comprehensive Income. Additionally, service cost is the only component eligible for capitalization (whereas under current GAAP, all components of net benefit cost are eligible for capitalization).
Generation, ComEd, PECO, BGE, BSC, PHI, Pepco, DPL, ACE and PHISCO participate in Exelon’s single employer pension and OPEB plans and apply multi-employer accounting. Multi-employer accounting is not impacted by this standard, so Exelon's subsidiary financial statements will not change. On Exelon’s consolidated financial statements, non-service cost components of pension and OPEB cost capitalizable under a regulatory framework will be reported as regulatory assets (currently, they are capitalizable under pension and OPEB accounting guidance and reported as PP&E). These regulatory assets will be amortized outside of operating income.
The standard is effective January 1, 2018 and requires retrospective application for the presentation of the service cost component and the other non-service cost components of net benefit cost and prospective application for the capitalization of only the service cost component of net benefit cost. Exelon will not early adopt this standard.
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 standard is effective January 1, 2019. Early adoption is permitted; however, the Registrants will not early adopt the standard. The issued guidance required a modified retrospective transition approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented (January 1, 2017). In July 2018, the FASB issued an amendment to the standard giving entities the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Exelon will elect this expedient.
The new 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 typefinance lease liabilities (capital(referred to as 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. Under the new guidance, an arrangement that conveys the right to control the use of an identified asset by obtaining substantially all of its economic benefits and directing how it is used is a lease, whereas the current definition focuses on the ability to control the use of the asset or to obtain its output. Quantitative and qualitative disclosures related to the amount, timing and judgments of an entity’s accounting for leases and the related cash flows are expanded. Disclosure requirements apply to both lessees and lessors, whereas current disclosures relate only to lessees. Significant changes to lease systems, processes and procedures are required to implement the requirements of the new standard. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from current GAAP. TheLessor accounting applied by a lessor is also largely unchanged from that applied under current GAAP. unchanged.
The standard is effectiveprovides a number of transition practical expedients that entities may elect. These include a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not

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

reassess initial direct costs associated with existing leases. The Registrants will elect this practical expedient.
In January 2018, the FASB issued additional guidance which provides another optional transition practical expedient. This practical expedient allows entities to not evaluate land easements under the new guidance at adoption if they were not previously accounted for as leases. The Registrants will elect this practical expedient.
The Registrants have assessed the lease standard and are executing a detailed implementation plan in preparation for adoption on January 1, 2019. Early adoption is permitted, howeverKey activities in the Registrants do not expectimplementation plan include:
Developing a complete lease inventory and abstracting the required data attributes into a lease accounting system that supports the Registrants' lease portfolios and integrates with existing systems.
Evaluating the transition practical expedients available under the guidance.
Identifying, assessing and documenting technical accounting issues, policy considerations and financial reporting implications.
Identifying and implementing changes to early adopt the standard. Lesseesprocesses and lessors are requiredcontrols to recognize and measure leases at the beginningensure all impacts of the earliest period presented using a modified retrospective approach. Refer to Note 24 — Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements in the Exelon 2016 Form 10-K for additional information regarding operating leases.new guidance are effectively addressed.
Impairment of Financial Instruments (Issued June 2016): Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects the entity’s current estimate of credit losses expected to be incurred over the life of the financial instrument. The standard does not make changes to the existing impairment models for non-financial assets such as fixed assets, intangibles and goodwill. The standard will be effective January 1, 2020 (with early adoption as of January 1, 2019 permitted) and 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.
Derivatives and Hedging (Issued September 2017): Allows more financial and nonfinancial hedging strategies to be eligible for hedge accounting.  The amendments are intended to more closely align hedge accounting with companies’ risk management strategies, simplify the application of hedge accounting, and increase transparency as to the scope and results of hedging programs.  There are also amendments related to effectiveness testing and disclosure requirements.  The guidance is effective January 1, 2019 and early adoption is permitted with a modified retrospective transition approach. The Registrants are currently assessing this standard but do not currently expect a significant impact given the limited activity for which the Registrants elect hedge accounting and because the Registrants do not anticipate increasing their use of hedge accounting as a resultimpacts of this standard.
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 steptwo-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. Exelon, Generation, ComEd, PHI and DPL have goodwill as of September 30, 2017.2018. This updated guidance is not currently expected to impact the Registrants’ financial reporting. The standard is effective January 1, 2020, with early adoption permitted, and must be applied on a prospective basis.

Derivatives and Hedging (Issued September 2017): Allows more financial and nonfinancial hedging strategies to be eligible for hedge accounting. The amendments are intended to more closely align hedge accounting with companies’ risk management strategies, simplify the application of hedge accounting, and increase transparency as to the scope and results of hedging programs. There are also amendments related to effectiveness testing and disclosure requirements. The standard is effective January 1, 2019, with early adoption permitted, and must be applied using a modified retrospective transition approach. Given the de-designation of hedge accounting relationships as of July 1, 2018, this standard is not expected to impact the Registrants' financial reporting as discussed in Note 10 - Derivative Financial Instruments.
62
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

ClarifyingCloud Computing Arrangements (Issued August 2018): Aligns the Definition ofrequirements for capitalizing costs incurred to implement a Business (Issued January 2017): Clarifies the definition of a businesscloud computing arrangement with the objective of addressing whether acquisitions (or dispositions) shouldinternal-use software guidance. As a result, certain implementation costs incurred in a cloud computing arrangement that are currently expensed as incurred will be accounted for as acquisitions/dispositions of assets or as acquisitions/dispositions of businesses. If substantially alldeferred and amortized over the fair valuenon-cancellable term of the assets acquired/disposed of 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/disposed of 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 will likely result in more acquisitions being accounted for as asset acquisitions.arrangement plus any reasonably certain renewal periods. The standard is effective January 1, 2018,2020, with early adoption permitted, and mustcan be applied onusing either a prospective basis. 
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 (current GAAP 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 January 1, 2018 with early adoption permitted. The guidance requires a modifiedor retrospective transition approach. A retrospective approach throughrequires a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. The Registrants are currently assessing the impacts of this standard.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash PaymentsDefined Benefit Plan Disclosures (Issued August 2016) and Restricted Cash (Issued November 2016)2018): In 2016,Eliminates existing disclosure requirements related to amounts in accumulated other comprehensive income expected to be recognized in net periodic benefit cost over 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,next year and the applicationeffects 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). The Registrants will adopt both standards on January 1, 2018 on a retrospective basis. Adoption of the second standard will result in aone-percentage-point change in presentation of restricted cash on the face of the Statement of Cash Flows; otherwise the Registrants do not expect that this guidance will have a significant impact 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 interestsassumed health care cost trend rates. In addition, new disclosures were added such as partnerships, unincorporated joint venturesthe weighted-average interest crediting rates for cash balance plans and limited liability companies, to be carried at fair value through net income, (ii) requires an incremental recognitionexplanation for the reasons for significant gains and disclosure requirementlosses 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 amortized cost at the amount that would be received to sell the asset or paid to transfer the liability.benefit obligation. The standard is effective January 1, 20182021, with early adoption permitted. The guidance requires a modified retrospective transition approach with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption. The Registrantspermitted, and must be applied retrospectively. Exelon will not early adopt this standard.standard in the fourth quarter 2018.
Fair Value Measurement Disclosures (Issued August 2018): Removes, modifies and adds disclosure requirements for fair value measurements and aims to reduce costs for preparers and improve the usefulness of information for financial statement users. The standard is effective January 1, 2020, with early adoption permitted, and most amendments must be applied retrospectively with the exception of three amendments which must be applied prospectively. In addition, entities are permitted to delay adoption of the additional disclosure requirements until the effective date and early adopt the removal or modified disclosure requirements. The Registrants do not expect thatare currently assessing the impacts of this guidance will have a significant impact onstandard as well as the Registrants' Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, and Consolidated Statements of Cash Flows.potential to early adopt.
3. 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 September 30, 20172018 and December 31, 2016,2017, Exelon, Generation, BGE, PHI and ACE collectively consolidated six and ninefive VIEs or VIE groups respectively, for which the applicable Registrant was the primary beneficiary (see

63
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

(see Consolidated Variable Interest Entities below). As of September 30, 20172018 and December 31, 2016,2017, Exelon and Generation collectively had significant interests in seven and eight, respectively, 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(see Unconsolidated Variable Interest Entities below).
Consolidated Variable Interest Entities
In July 2017, Generation entered into an arrangement to sell a 49% interest in ExGen Renewables Partners, LLC (the Renewable JV) to an outside investor for $400 million of cash plus immaterial working capital and other customary post-closing adjustments. The Renewable JV meets the definition of a VIE because the Renewable JV has a similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. Additionally, under the VIE guidance Generation is the primary beneficiary because Generation maintains the controlling financial interest; therefore, Generation will continue to consolidate the Renewable JV.
Generation owned 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 required 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 (EPC) contract (see Note 14 - Debt and Credit Agreements for additional details on Albany Green Energy, LLC). During the third quarter of 2017, the ownership of the entity increased to 99%, all payment obligations related to the EPC contract were satisfied, and the parental guarantee provided by Generation was terminated. As a result, the entity is now sufficiently capitalized and no longer meets the definition of a VIE. The entity was previously disclosed in “a group of companies formed by Generation to build, own and operate other generating facilities” as of December 31, 2016. However, the biomass facility will continue to be consolidated by Generation under the voting interest model.
RSB BondCo LLC (BondCo) is a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, issue and service bonds secured by rate stabilization property. BGE is required to remit all payments it receives from all residential customers through non-bypassable, rate stabilization charges to BondCo. In the second quarter of 2017 the rate stabilization bonds were fully redeemed and BGE remitted its final payment to BondCo. During the nine months ended September 30, 2017, BGE remitted $22 million to BondCo. During the three and nine months ended September 30, 2016, BGE remitted $27 million and $64 million to BondCo, respectively. Upon the redemption of the bonds, BondCo no longer meets the definition of a variable interest entity and is removed from the list of consolidated VIEs noted below.
During 2009, Constellation formed a retail gas group to enter into a collateralized gas supply agreement with a third-party gas supplier.  The retail gas group was determined to be a VIE because there was not sufficient equity to fund the group’s activities without additional credit support and a $75 million parental guarantee provided by Generation. As the primary beneficiary, Generation consolidated the retail gas group.  During the second quarter of 2017, the collateral structure was terminated with the third-party gas supplier except for the $75 million parental guarantee provided by Generation.  Although the parental guarantee will remain, this is considered customary and reasonable for the unsecured position Generation has with the third-party gas supplier.  As a result of the termination, the retail gas group no longer met the definition of a VIE and was removed from the list of consolidated VIEs noted below.  However, the retail gas group continues to be consolidated by Generation under the voting interest model.
As of September 30, 2018 and December 31, 2017, Exelon's and Generation's consolidated VIEs consist of:
Renewableenergy related companies involved in distributed generation, backup generation and energy development
renewable energy project companies formed by Generation to build, own and operate renewable power facilities which were previously separated into two separate VIE groups for solar project limited liability companies and wind project companies as of December 31, 2016,
Constellation EG, LLC (a company that operates back-up generation for a third-party), which was previously included in a group of companies formed by Generation to build, own and operate other generating facilities as of December 31, 2016,
certain retail power and gas companies for which Generation is the sole supplier of energy,
CENG,
2015 ESA Investco, LLC, a company that holds an equity method investment in a distributed energy company, and

64
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

certain retail power and gas companies for which Generation is the sole supplier of energy, and
CENG.
As of September 30, 2018 and December 31, 2017, Exelon's, PHI's and ACE's consolidated VIE consistsconsist of:
ATF,, 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.
As of September 30, 20172018 and December 31, 2016,2017, ComEd, PECO, BGE, Pepco and DPL did not have any material consolidated VIEs.
As of September 30, 20172018 and December 31, 2016,2017, Exelon and Generation provided the following support to their respective consolidated VIEs:
Generation provides operating and capital funding to the renewable energy project companies and there is limited recourse to Generation related to certain renewable energy project companies.
Generation provides operating and capital funding to Constellation EG, LLC.one of the energy related companies involved in backup generation.
Generation provides approximately $31$34 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy.
Exelon and Generation, where indicated, provide the following support to CENG (see Note 5—Investment in Constellation Energy Nuclear Group, LLC and Note 27—Related Party Transactions of the Exelon 2016 Form 10-K for additional information regarding Generation's and Exelon’s transactions with CENG):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 were suspended during the term of the Reliability Support Services Agreement (RSSA),RSSA, through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017, (see Note 5 — Regulatory Matters for additional details),
Generation provided a $400 million loan to CENG. As of September 30, 2017,2018, the remaining obligation is $328$194 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 1817 — Commitments and Contingencies for more details)additional information),
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 $8 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 18 — Commitments and Contingencies for more details), and

65
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(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.

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

As of September 30, 20172018 and December 31, 2016,2017, Exelon, PHI and ACE provided the following support to their respective consolidated VIE:
In the case of ATF, 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 and nine months ended September 30, 2017,2018, ACE transferred $11$9 million and $39$23 million to ATF, respectively. During the three and nine months ended September 30, 2016,2017, ACE transferred $20$11 million and $47$39 million to ATF, respectively.
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, PHI and ACE did not provide any additional material financial support to the VIEs;
Exelon, Generation, 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, PHI's or ACE's general credit.
The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants' consolidated financial statements at September 30, 20172018 and December 31, 20162017 are as follows:
September 30, 2017 December 31, 2016
    Successor         Successor  September 30, 2018 December 31, 2017
Exelon(a)
 Generation 
PHI (a)
 ACE 
Exelon(a)(b)
 Generation BGE 
PHI (a)
 ACE
Exelon(a)
 Generation 
PHI(a)
 ACE 
Exelon(a)
 Generation 
PHI(a)
 ACE
Current assets$657
 $644
 $13
 $9
 $954
 $916
 $23
 $14
 $9
$891
 $881
 $10
 $7
 $662
 $652
 $10
 $6
Noncurrent assets9,252
 9,222
 30
 22
 8,563
 8,525
 3
 35
 23
9,259
 9,233
 26
 19
 9,317
 9,286
 31
 23
Total assets$9,909

$9,866

$43
 $31

$9,517

$9,441

$26

$49
 $32
$10,150

$10,114

$36
 $26

$9,979

$9,938

$41
 $29
Current liabilities$404
 $367
 $37
 $33
 $885
 $802
 $42
 $42
 $37
$329
 $303
 $26
 $23
 $308
 $272
 $36
 $32
Noncurrent liabilities3,290
 3,215
 75
 67
 2,713
 2,612
 —
 101
 89
3,284
 3,232
 52
 45
 3,316
 3,250
 66
 58
Total liabilities$3,694

$3,582

$112
 $100

$3,598

$3,414

$42

$143
 $126
$3,613

$3,535

$78
 $68

$3,624

$3,522

$102
 $90
_________
(a)Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
(b)Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.

66
Table of Contents
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 September 30, 20172018 and December 31, 2016,2017, these assets and liabilities primarily consisted of the following:
September 30, 2017 December 31, 2016
    Successor         Successor  September 30, 2018 December 31, 2017
Exelon (a)

Generation 
PHI (a)
 ACE 
Exelon(a)(b)
 Generation BGE 
PHI (a)
 ACE
Exelon(a)

Generation
PHI(a)
 ACE 
Exelon(a)
 Generation 
PHI(a)
 ACE
Cash and cash equivalents$130
 $130
 $—
 $—
 $150
 $150
 $—
 $—
 $—
$316
 $316
 $—
 $—
 $126
 $126
 $—
 $—
Restricted cash85
 76
 9
 9
 59
 27
 23
 9
 9
77
 70
 7
 7
 64
 58
 6
 6
Accounts receivable, net    
         
      
       
  
Customer139
 139
 —
 —
 371
 371
 —
 —
 —
165
 165
 —
 —
 170
 170
 —
 —
Other25
 25
 —
 —
 48
 48
 —
 —
 —
30
 30
 —
 —
 25
 25
 —
 —
Mark-to-market derivatives assets—
 —
 —
 —
 31
 31
 —
 —
 —
Inventory    
         
  
Inventory, net    
       
  
Materials and supplies196
 196
 —
 —
 199
 199
 —
 —
 —
214
 214
 —
 —
 205
 205
 —
 —
Other current assets56
 52
 4
 —
 50
 44
 —
 5
 —
65
 62
 3
 —
 45
 41
 4
 —
Total current assets631

618

13
 9
 908

870

23

14
 9
867

857

10
 7
 635

625

10
 6
Property, plant and equipment, net6,213
 6,213
 —
 —
 5,415
 5,415
 —
 —
 —
6,158
 6,158
 —
 —
 6,186
 6,186
 —
 —
Nuclear decommissioning trust funds2,415
 2,415
 —
 —
 2,185
 2,185
 —
 —
 —
2,523
 2,523
 —
 —
 2,502
 2,502
 —
 —
Goodwill—
 —
 —
 —
 47
 47
 —
 —
 —
Mark-to-market derivative assets—
 —
 —
 —
 23
 23
 —
 —
 —
Other noncurrent assets261
 231
 30
 22
 315
 277
 3
 35
 23
256
 230
 26
 19
 274
 243
 31
 23
Total noncurrent assets8,889

8,859

30
 22
 7,985

7,947

3

35
 23
8,937

8,911

26
 19
 8,962

8,931

31
 23
Total assets$9,520

$9,477

$43
 $31
 $8,893

$8,817

$26

$49
 $32
$9,804

$9,768

$36
 $26
 $9,597

$9,556

$41
 $29
Long-term debt due within one year$182
 $146
 $36
 $32
 $181
 $99
 $41
 $40
 $35
$97
 $72
 $25
 $22
 $102
 $67
 $35
 $31
Accounts payable104
 104
 —
 —
 269
 269
 —
 —
 —
128
 128
 —
 —
 114
 114
 —
 —
Accrued expenses90
 89
 1
 1
 119
 116
 1
 2
 2
73
 72
 1
 1
 67
 66
 1
 1
Mark-to-market derivative liabilities—
 —
 —
 —
 60
 60
 —
 —
 —
Unamortized energy contract liabilities17
 17
 —
 —
 15
 15
 —
 —
 —
16
 16
 —
 —
 18
 18
 —
 —
Other current liabilities11
 11
 —
 —
 30
 30
 —
 —
 —
14
 14
 —
 —
 7
 7
 —
 —
Total current liabilities404
 367
 37
 33
 674
 589
 42

42
 37
328
 302
 26
 23
 308
 272
 36
 32
Long-term debt1,172
 1,097
 75
 67
 641
 540
 —
 101
 89
1,087
 1,035
 52
 45
 1,154
 1,088
 66
 58
Asset retirement obligations2,009
 2,009
 —
 —
 1,904
 1,904
 —
 —
 —
2,116
 2,116
 —
 —
 2,035
 2,035
 —
 —
Pension obligation(c)
—
 —
 —
 —
 9
 9
 —
 —
 —
Unamortized energy contract liabilities9
 9
 —
 —
 22
 22
 —
 —
 —
Other noncurrent liabilities94
 94
 —
 —
 106
 106
 —
 —
 —
75
 75
 —
 —
 121
 121
 —
 —
Total noncurrent liabilities3,284
 3,209
 75
 67
 2,682
 2,581
 —

101
 89
3,278
 3,226
 52
 45
 3,310
 3,244
 66
 58
Total liabilities$3,688
 $3,576
 $112
 $100
 $3,356
 $3,170
 $42

$143
 $126
$3,606
 $3,528
 $78
 $68
 $3,618
 $3,516
 $102
 $90
_________
(a)Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
(b)Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
(c)Includes the retail gas pension obligation, which is presented as a net asset balance within the Prepaid pension asset line item on Generation’s Consolidated Balance Sheets. See Note 14 - 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

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

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 predominantlypredominately related to working capital accounts

67
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

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 September 30, 2018 and December 31, 2017, Exelon's and Generation's unconsolidated VIEs consist of:
Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required.
Asset sale agreement with ZionSolutions, LLC and EnergySolutions, Inc. in which Generation has a variable interest but has concluded that consolidation is not required.
Equity investments in distributed energy companies and energy generating facilities for which Generation has concluded that consolidation is not required.
As of September 30, 20172018 and December 31, 2016, ComEd, PECO, BGE, PHI, Pepco, ACE, and DPL2017, the Utility Registrants did not have any material unconsolidated VIEs.
As of September 30, 20172018 and December 31, 2016,2017, Exelon and Generation had significant unconsolidated variable interests in seven and eight VIEs respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity investments and certain commercial agreements. The decrease in the number of unconsolidated VIEs is due to the sale of an equity investment in an energy generating facility. 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 $17$15 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 $17$15 million included in Investments on Exelon’s and Generation’s Consolidated Balance Sheets.Sheets. The risk of a loss was assessed to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.
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 a distributed energy company, which is an unconsolidated VIE. 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 contributed a total of $227 million of equity incrementally from inception through the first quarter of 2017 in proportion of their ownership interests. Generation and the tax equity investor provided 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. As all equity contributions were made as of the first quarter 2017, there is no further payment obligation under the parental guarantee.

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

The following tables present summary information about Exelon's and Generation’s significant unconsolidated VIE entities:  
September 30, 2017
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
September 30, 2018
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
Total assets(a)
$635
 $519
 $1,154
$606
 $481
 $1,087
Total liabilities(a)
39
 229
 268
36
 221
 257
Exelon's ownership interest in VIE(a)
—
 259
 259
—
 232
 232
Other ownership interests in VIE(a)
596
 31
 627
570
 28
 598
Registrants’ maximum exposure to loss:    
    
Carrying amount of equity method investments—
 259
 259
—
 232
 232
Contract intangible asset9
 —
 9
8
 —
 8
Debt and payment guarantees—
 —
 —
Net assets pledged for Zion Station decommissioning(b)
4
 —
 4
—
 —
 —
December 31, 2016
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
December 31, 2017
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
Total assets(a)
$638
 $567
 $1,205
$625
 $509
 $1,134
Total liabilities(a)
215
 287
 502
37
 228
 265
Exelon's ownership interest in VIE(a)
—
 248
 248
—
 251
 251
Other ownership interests in VIE(a)
423
 32
 455
588
 30
 618
Registrants’ maximum exposure to loss:    
    
Carrying amount of equity method investments—
 264
 264
—
 251
 251
Contract intangible asset9
 —
 9
8
 —
 8
Debt and payment guarantees—
 3
 3
Net assets pledged for Zion Station decommissioning(b)
9
 —
 9
2
 —
 2
_________
(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 $57$9 million and $113$39 million as of September 30, 20172018 and December 31, 2016,2017, respectively; offset by payables to ZionSolutions, LLC of $53$9 million and $104$37 million as of September 30, 20172018 and December 31, 2016,2017, respectively. These items are included to provide information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE. See Note 13 - Nuclear Decommissioning— Asset Retirement Obligations for additional details.information.
For each of the unconsolidated VIEs, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.
BGE
The financing trust4. Mergers, Acquisitions and Dispositions (Exelon and Generation)
Acquisition of BGE, BGE Capital Trust II, was created in 2003 for the purpose of issuing mandatorily redeemable trust preferred securities.  In the third quarter of 2017, BGE redeemed the securities pursuantFirstEnergy Solutions Load Business
On July 9, 2018, Generation entered into an Asset Purchase Agreement (the Purchase Agreement) with FirstEnergy Solutions Corporation (FirstEnergy). Pursuant to the optional redemption provisionsPurchase Agreement, FirstEnergy will assign all of the Indenture, under which the subordinated debt securities were issued,its retail electricity and dissolved BGE Capital Trust II.  Priorwholesale load serving contracts and certain other related commodity contracts to dissolutionGeneration for an all cash purchase price of $140 million. Pursuant to the BGE Capital Trust II was not consolidated in Exelon's or BGE's financial statements. BGE concluded it did not have a significant variable interest in BGE Capital Trust II as BGE financed its equity interest in the financing trust through the issuance of subordinated debt and, therefore, had no equity at risk.  See Note 14 - Debt and Credit Agreements of the Exelon 2016 Form 10-K for additional information.

69
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

4. Mergers, AcquisitionsPurchase Agreement, Generation has agreed to use its commercially reasonable efforts to replace the guarantees and Dispositions (Exelon,other credit support currently being provided by FirstEnergy in support of the ongoing competitive retail businesses and to reimburse FirstEnergy for any payments arising pursuant to such arrangements continuing for any post-closing period.
The transaction is expected to close in the fourth quarter of 2018. The closing of the transaction is subject to certain conditions including the approval of the Purchase Agreement by the United States Bankruptcy Court for the Northern District of Ohio following the auction and expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Either party may terminate the Purchase Agreement if the transaction has not been consummated by December 31, 2018. The Purchase Agreement also includes various representations, warranties, covenants, indemnification and other provisions customary for a transaction of this nature.
Acquisition of Handley Generating Station
On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware, which resulted in Exelon and Generation PHI, Pepcodeconsolidating EGTP's assets and DPL)liabilities from their consolidated financial statements in the fourth quarter of 2017. Concurrently with the Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP's generating plants, the Handley Generating Station, subject to a potential adjustment for fuel oil and assumption of certain liabilities. In the Chapter 11 Filings, EGTP requested that the proposed acquisition of the Handley Generating Station be consummated through a court-approved and supervised sales process. The acquisition was approved by the Bankruptcy Court in January 2018 and closed on April 4, 2018 for a purchase price of $62 million. The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders.
Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)
On March 31, 2017, Generation acquired the 838842 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy) for a total purchase price of $289 million, which consisted of a cash purchase price of $110 million and a net cost reimbursement to and on behalf of Entergy of $179 million. As part of the acquisition agreements, Generation provided nuclear fuel and reimbursed Entergy for incremental costs to prepare for and conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the plant for the period after the refueling outage through the acquisition closing date. These reimbursements covered costs that Entergy otherwise would have avoided had it shut down the plant as originally intended in January 2017. The amounts reimbursed by Generation were offset by FitzPatrick's electricity and capacity sales revenues for this same post-outage period. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumed the obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034. As of September 30, 2017, Generation had remitted purchase price consideration of $289 million (including $235 million of cash and $54 million of nuclear fuel) to and on behalf of Entergy.
The fair values of FitzPatrick’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices. The valuations performed in the first quarter of 2017 to determine the fair value of the FitzPatrick assets acquired and liabilities assumed were preliminary. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.
Duringupdated in the third quarter of 2017, certain modifications were made to the initial preliminary valuation amounts for acquired property, plant and equipment, the decommissioning ARO, pension and OPEB obligations and related deferred tax liabilities, resulting in a $3 million net increase in assets acquired and liabilities assumed. Additionally, in the third quarter a2017. The purchase price settlement payment of $4 million was received from Entergy. Consequently, Exelon and Generation recordedallocation is now final.
For the three months ended March 31, 2017, an additional after-tax bargain purchase gain of $7 million for the three months ended September 30, 2017. For the nine months ended September 30, 2017, the after-tax bargain purchase gain of $233$226 million is included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income and primarily reflects differences in strategies between Generation and Entergy for the intended use and ultimate decommissioning of the plant. There are no further adjustments expected to be made toDuring the allocationthird quarter of the purchase price. See Note 13 - Nuclear Decommissioning2017, Exelon and Note 14 - Retirement Benefits for additional information regarding the FitzPatrick decommissioning ARO and pension and OPEB updates.Generation


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

recorded an additional after-tax bargain purchase gain of $7 million for the three months ended September 30, 2017. The total after-tax bargain purchase gain recorded at Exelon and Generation was $233 million for the twelve months ended December 31, 2017. See Note 13 — Asset Retirement Obligations and Note 14 — Retirement Benefits for additional information regarding the FitzPatrick decommissioning ARO and pension and OPEB updates.
The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the FitzPatrick acquisition by Generation as of September 30, 2017:Generation:
Cash paid for purchase price $110
Cash paid for net cost reimbursement 125
Nuclear fuel transfer 54
Total consideration transferred $289
   
Identifiable assets acquired and liabilities assumed  
Current assets $60
Property, plant and equipment 298
Nuclear decommissioning trust funds 807
Other assets(a)
 114
Total assets $1,279
   
Current liabilities $6
Nuclear decommissioning ARO 444
Pension and OPEB obligations 33
Deferred income taxes 149
Spent nuclear fuel obligation 110
Other liabilities 15
Total liabilities $757
Total net identifiable assets, at fair value $522
   
Bargain purchase gain (after-tax) $233
_________
(a)Includes a $110 million asset associated with a contractual right to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated with the DOE one-time fee obligation. See Note 24-Commitments23-Commitments and Contingencies of the Exelon 20162017 Form 10-K for additional backgroundinformation regarding SNF obligations to the DOE.
ForExelon and Generation incurred $16 million and $47 million of merger and integration costs related to FitzPatrick for the three and nine months ended September 30, 2017, Exelon and Generation incurred $6 million and $53 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. Exelon and Generation did not incur any merger and integration costs related to FitzPatrick for the three and nine months ended September 30, 2018.
AcquisitionDisposition of ConEdison Solutions (Exelon and Generation)Oyster Creek
On September 1, 2016,July 31, 2018, Generation acquiredentered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the competitive retail electricitysale and natural gas business of Consolidated Edison Solutions, Inc. (ConEdison Solutions), a subsidiary of Consolidated Edison, Inc. for a purchase price of $257 million including net working capital of $204 million. The renewable energy, sustainable services and energy efficiency businesses of ConEdison Solutions are excluded from the transaction.
The 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. The purchase price equaled the estimated fair valuedecommissioning of the net assets acquired and the liabilities assumed and, therefore, no goodwill or bargain purchase was recorded as of the acquisition date. The purchase price allocation is now final.Oyster Creek Generating Station (Oyster Creek) located in Forked River, New Jersey. On September 17, 2018, Oyster Creek permanently ceased generation operations.

71
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

The following table summarizesUnder the final acquisition-date fair valueterms of the consideration transferred andtransaction, Generation will transfer to OCEP substantially all the assets and liabilities assumedassociated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the ConEdison Solutions acquisition by Generation:site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. In addition to the assumption of liability for the full decommissioning and ongoing management of spent fuel, other consideration to be received in the transaction is contingent on several factors, including a requirement that Generation deliver a minimum NDT fund balance at closing, subject to adjustment for specific terms that include income taxes that would be imposed on any net unrealized built-in gains and certain decommissioning activities to be performed during the pre-close period after the unit shuts down in the fall of 2018 and prior to the anticipated close of the transaction. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events.
Total consideration transferred $257
   
Identifiable assets acquired and liabilities assumed  
Working capital assets $204
Property, plant and equipment 2
Mark-to-market derivative assets 6
Unamortized energy contract assets 100
Customer relationships 9
Other assets 1
Total assets $322
   
Mark-to-market derivative liabilities $65
Total liabilities $65
Total net identifiable assets, at fair value $257
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 subsidiarythe transaction, in the casethird quarter 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 to2018, Exelon and Generation reclassified certain Oyster Creek assets and the transfer of PHI, Pepco, DPLliabilities on Exelon’s and ACE to a special purpose subsidiary of EEDC.
Regulatory Matters
ApprovalGeneration’s Consolidated Balance Sheets as held for sale at their respective fair values. Upon remeasurement of the mergerOyster Creek ARO in Delaware, New Jersey, Maryland and the Districtthird quarter of Columbia was conditioned upon2018, Exelon and PHI agreeingGeneration recognized an $84 million pre-tax charge to certain commitments including where applicable: customer rate credits, funding for energy efficiency and delivery system modernization programs, a green sustainability fund, workforce development initiatives, charitable contributions, renewable generation and other required commitments. In addition, the orders approving the merger in Delaware, New Jersey, and Maryland include a “most favored nation” provision which, generally, requires allocation of merger benefits proportionally across all the jurisdictions.
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 amount, excluding renewable generation commitments and charitable contributions). These filings reflected agreements reached with certain parties to the merger proceedings in these jurisdictions. In 2016, the DPSC and NJBPU approved the amounts and allocations of the additional merger benefits for Delaware and New Jersey, respectively. On April 12, 2017, the MDPSC issued an order approving the amounts of the additional merger benefits for Maryland, but amending the proposed allocations of the benefits. The amended allocations do not have a material effect on any of the Registrants' financial statements. No changes in commitment cost levels are required in the District of Columbia.
During the second quarter of 2017, Exelon finalized the application of $8 million funding for low- and moderate-income customers in the Pepco Maryland and DPL Maryland service territories.  This resulted in an adjustment to merger commitment costs recorded at Exelon Corporate, Pepco, and DPL.  Exelon Corporate recorded an increase of $8 million and Pepco and DPL recorded a decrease of $6 million and $2 million, respectively, in Operating and maintenance expense.

Completion of the transaction contemplated by the sale agreement is subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and the receipt of a private letter ruling from the IRS. Generation currently anticipates satisfaction of the closing conditions to occur in the second half of 2019.
Other Asset Disposition
72In December 2017, Generation entered into an agreement to sell its interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution systems. As a result, as of December 31, 2017, certain assets and liabilities were classified as held for sale and included in the Other current assets and Other current liabilities balances on Exelon's and Generation's Consolidated Balance Sheet. On February 28, 2018, Generation completed the sale of its interest for $87 million, resulting in a pre-tax gain which is included within Gain on sales of assets and businesses on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. In June 2018, additional proceeds were received, and a pre-tax gain was recorded within Gain on sales of assets and businesses on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
Table
5. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of Contentsgoods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution and transmission services. The performance obligations associated with these sources of revenue are further discussed below.
Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrant's have elected to use the right to invoice practical expedient for the contracts within these revenue categories and generally recognize revenue in the amount for

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

Thewhich they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.
Competitive Power Sales (Exelon and Generation)
Generation sells power and other energy-related commodities to both wholesale and retail customers across multiple geographic regions through its customer-facing business, Constellation. Power sale contracts generally contain various performance obligations including the delivery of power and other energy-related commodities such as capacity, ZECs, RECs or other ancillary services. Certain performance obligations such as power and capacity are generally delivered over time whereas other performance obligations such as RECs and ZECs are generally delivered at a point in time. In either case, revenues related to all of the performance obligations in such bundled power sale contracts are generally recognized concurrently as the power is generated. Except as noted in the paragraph below, there are no significant judgments in allocating the transaction price since all performance obligations are satisfied simultaneously upon the generation of power. Payment terms generally require that the customers pay for the power or the energy-related commodity within the month following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the acquisition date:
 Expected Payment Period       Successor  
Description Pepco DPL ACE PHI Exelon
Rate credits2016 - 2017 $91
 $67
 $101
 $259
 $259
Energy efficiency2016 - 2021 —
 —
 —
 —
 122
Charitable contributions2016 - 2026 28
 12
 10
 50
 50
Delivery system modernizationQ2 2017 —
 —
 —
 —
 22
Green sustainability fundQ2 2017 —
 —
 —
 —
 14
Workforce development2016 - 2020 —
 —
 —
 —
 17
Other  1
 5
 —
 6
 29
Total  $120
 $84
 $111
 $315
 $513
Pursuantdelivery to the orders approvingcustomer and there are generally no significant financing components.
Certain contracts may contain limits on the merger, Exelon made $73 million, $46 million and $49 milliontotal amount of equity contributionsrevenue we are able to Pepco, DPL and ACE, respectively, incollect over the second quarter of 2016 to fund the after-tax amountsentire term of the customer bill credit andcontract. In such cases, the customer base rate credit commitments.
In addition, Exelon is committed to develop or to assist inRegistrants estimate the commercial development of approximately 37 MWs of new generation in Maryland, District of Columbia, and Delaware, 27 MWs of which aretotal consideration expected to be completedreceived over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.
Competitive Natural Gas Sales (Exelon and Generation)
Generation sells natural gas on a full requirements basis or for an agreed upon volume to both commercial and residential customers. The primary performance obligation associated with natural gas sale contracts is the delivery of the natural gas to the customer. Revenues related to the sale of natural gas are recognized over time as the natural gas is delivered to and consumed by 2018.the customer. Payment from customers is typically due within the month following delivery of the natural gas to the customer and there are generally no significant financing components.
Other Competitive Products and Services (Exelon and Generation)
Generation also sells other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers. These investmentscontracts generally contain a single performance obligation, which is the construction and/or installation of the asset for the customer. The average contract term for these projects is approximately 18 months. Revenues, and associated costs, are expectedrecognized throughout the contract term using an input method to measure progress towards completion. The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total approximately $137 million, are expected to be primarily capital in nature, and will generate future earnings at Exelon and Generation. Investment costslabor hours expended. The total amount of revenue that will be recognized as incurredis based on the agreed upon contractually-stated amount. Payments from customers are typically due within 30 or 45 days from the date the invoice is generated and 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.
Pursuantsent to the various jurisdictions' merger approval conditions, over specified periods Pepco,customer.
Regulated Electric and Gas Tariff Sales (Exelon and the Utility Registrants)
The Utility Registrants sell electricity and electricity distribution services to residential, commercial, industrial and governmental customers through regulated tariff rates approved by their state regulatory commissions. PECO, BGE and DPL also sell natural gas and ACE are not permittedgas distribution services to reduce employment levels due to involuntary attritionresidential, commercial, and industrial customers through regulated tariff rates approved by their state regulatory commissions. The performance obligation associated with the merger integration process and have made other commitments regarding hiring and relocation of positions.
In July 2015, the OPC, Public Citizen, Inc., the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed motions to stay the MDPSC order approving the merger. The Circuit Court judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, CCAN and Public Citizen, Inc.  On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed notices of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment that the MDPSC did not err in approving the merger. The OPC and Sierra Club filed petitions seeking further review in the Court of Appeals of Maryland, whichthese tariff sale contracts is the highest court in Maryland. On June 21, 2017, the Courtdelivery of Appeals granted discretionary review of the January 27, 2017 decision by the Maryland Court of Special Appeals. The Maryland Court of Appeals will review the OPC argumentelectricity and/or natural gas. Tariff sales are generally considered daily contracts given that the MDPSC did not properly consider the acquisition premium paid to PHI shareholders under Maryland’s merger approval standard and the Sierra Club’s argument that the merger would harm the renewable and distributed generation markets. The two lower courts examining these issues rejected these arguments, which Exelon believes are without merit. All briefs have been filed and oral arguments were presented to the court on October 10, 2017.
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 July 20, 2017, the Court issued an opinion rejecting all of appellants’ arguments and affirming the Commission’s decision approving the merger.customers

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

Accountingcan discontinue service at any time. Revenues are generally recognized over time (each day) as the electricity and/or natural gas is delivered to customers. Payment terms generally require that customers pay for the Merger Transactionservices within the month following delivery of the electricity or natural gas to the customer and there are generally no significant financing components or variable consideration.
The totalElectric and natural gas utility customers have the choice to purchase price consideration of approximately $7.1 billionelectricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the PHI Merger consistedsupply and distribution of cash paidelectricity and/or natural gas, they recognize revenue related only to PHI shareholders, cash paidthe distribution services when customers purchase their electricity or natural gas from competitive suppliers.
Regulated Transmission Services (Exelon and the Utility Registrants)
Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants are members of PJM, the regional transmission organization designated by FERC to coordinate the movement of wholesale electricity in PJM’s region, which includes portions of the mid-Atlantic and Midwest. In accordance with FERC-approved rules, the Utility Registrants and other transmission owners in the PJM region make their transmission facilities available to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants and other transmission owners. The performance obligations associated with the Utility Registrants’ contract with PJM include (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid. These performance obligations are satisfied over time, and Utility Registrants utilize output methods to measure the progress towards their completion. Passage of time is used for PHI preferred securitiesNITS and cash paidaccess to the wholesale grid and MWhs of energy transported over the wholesale grid is used for PHI stock-based compensation equity awards as follows:scheduling, system control and dispatch services. PJM pays the Utility Registrants for these services on a weekly basis and there are no financing components or variable consideration.
Costs to Obtain or Fulfill a Contract with a Customer (Exelon and Generation)
(In millions of dollars, except per share data)Total Consideration
Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016)$6,933
Cash paid for PHI preferred stock180
Cash paid for PHI stock-based compensation equity awards(a)
29
Total purchase price$7,142
_________
(a)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 $27.25Generation incurs incremental costs in order to execute certain retail power and gas sales contracts. These costs primarily relate to retail broker fees and sales commissions. Generation has capitalized such contract acquisition costs in the amount of cash in exchange for each share of PHI common stock outstanding$30 million and $26 million 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, nonconvertibleSeptember 30, 2018 and nontransferable preferred securities of PHI prior to December 31, 2015. On March 23, 2016,2017, respectively, within Other current assets and Other deferred debits in Exelon’s and Generation’s Consolidated Balance Sheets. These costs are capitalized when incurred and amortized using the preferred securities were cancelled for no consideration tostraight-line method over the average length of such retail contracts, which is approximately 2 years. Exelon and accordingly, the $180 million cash consideration previously paid to acquire the preferred securities was treated as purchase price consideration.
The preliminary valuations performedGeneration recognized amortization expense associated with these costs in the first quarteramount of 2016 were updated$6 million and $16 million for the three and nine months ended September 30, 2018, respectively, and $7 million and $24 million for the three and nine months ended September 30, 2017, respectively, within Operating and maintenance expense in the second, third, and fourth quarters of 2016. There were no adjustments to the purchase price allocation in the first quarter of 2017 and the purchase price allocation is now final.
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'sGeneration’s Consolidated Balance Sheets as follows:Statements of Operations and Comprehensive Income. Generation does not incur material costs to fulfill contracts with customers that are not already capitalized under existing guidance. In addition, the Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.
Contract Balances (All Registrants)
Purchase Price Allocation(a)
 
Current assets$1,441
Property, plant and equipment11,088
Regulatory assets5,015
Other assets248
Goodwill4,005
Total assets$21,797
  
Current liabilities$2,752
Unamortized energy contracts1,515
Regulatory liabilities297
Long-term debt, including current maturities5,636
Deferred income taxes3,447
Pension and OPEB obligations821
Other liabilities187
Total liabilities$14,655
Total purchase price$7,142
Contract Assets
_________
(a)Amounts shown reflect the final purchase price allocation and the correction of a reporting error identified and corrected in the second quarter of 2016. The error had resulted in a gross up of certain assets and liabilities related to legacy PHI intercompany and income tax receivable and payable balances.

Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Accounts receivable, net -

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

On its successor financial statements, PHI has recorded, beginning March 24, 2016, Membership interest equityCustomer, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets. The following table provides a rollforward of $7.2 billion, whichthe contract assets reflected on Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to September 30, 2018:
Contract Assets Exelon and Generation
Balance as of January 1, 2018 $283
Increases as a result of changes in the estimate of the stage of completion 34
Amounts reclassified to receivables (120)
Balance at September 30, 2018 $197
The Utility Registrants do not have any contract assets.
Contract Liabilities
Generation records contract liabilities when consideration is greater thanreceived or due prior to the satisfaction of the performance obligations. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on the total $7.1 billion purchase price, reflecting the impact ofconsideration to be received by Generation. Generation records contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon’s and Generation’s Consolidated Balance Sheets. The following table provides a $59 million deferred tax liability recorded only at Exelon Corporate to reflect unitary state income tax consequencesrollforward of the merger.contract liabilities reflected on Exelon's and Generation's Consolidated Balance Sheet from January 1, 2018 to September 30, 2018:
Contract Liabilities Exelon and Generation
Balance as of January 1, 2018 $35
Increases as a result of additional cash received or due 389
Amounts recognized into revenues (387)
Balance at September 30, 2018 $37
The excessUtility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the purchase price overperformance obligations. As of September 30, 2018 and December 31, 2017, the estimated fair value of the assets acquired and theUtility Registrants' contract 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 abilitywere immaterial.
Transaction Price Allocated 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 assigned to PHI's reportable units Pepco, DPL and ACE inRemaining Performance Obligations (All Registrants)
The following table shows the amounts of $1.7 billion, $1.1 billion and $1.2 billion, respectively. None of this goodwill isfuture revenues expected to be tax deductible.
Immediately following closing of the merger, $235 million of net assets includedrecorded 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 assumptionseach year for performance obligations 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,unsatisfied or rate 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 5 - 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 Sheetspartially unsatisfied as of September 30, 2017.2018. Generation has elected the exemption which permits the exclusion from this disclosure of certain variable contract consideration. As such, the majority of Generation’s power and gas sales contracts are excluded from this disclosure as they contain variable volumes and/or variable pricing. Thus, this disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The difference between theaverage contract priceterm varies by customer type and the market price at the acquisition datecommodity but ranges from one month to several years.
The majority of the Merger was recognizedUtility Registrants’ tariff sale contracts are generally day-to-day contracts and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure. Further, the Utility Registrants have elected the exemption to not disclose the transaction price allocation to remaining performance obligations for each contract as eithercontracts with an intangible assetoriginal expected duration of one year 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.less. As such, Exelongas and PHI did not push-down the application of acquisition accounting to PHI's utility registrants,electric tariff sales contracts and therefore the financial statements of Pepco, DPL and ACE do not reflect the revaluation of any assets and liabilities.transmission revenue contracts are excluded from this disclosure.

75
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

The current impact of PHI, including its unregulated businesses, on Exelon's Consolidated Statements of Operations and Comprehensive Income includes:
 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
Operating revenues$1,347
 $1,437
 $3,679
 $2,656
Net income (loss)176
 169
 382
 (92)
 2019 2020 2021 2022 2023 and thereafter Total
Exelon$647
 $302
 $119
 $47
 $137
 $1,252
Generation647
 302
 119
 47
 137
 1,252
ForRevenue Disaggregation (All Registrants)
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the threenature, amount, timing, and nine months ended September 30, 2017uncertainty of revenue and 2016,cash flows are affected by economic factors. See Note 19 — Segment Information for the Registrants have recognized costs to achieve the PHI acquisition as follows:
 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
Acquisition, Integration and Financing Costs(a)
2017 2016 2017 2016
Exelon$(8) $20
 $10
 $123
Generation5
 9
 18
 29
ComEd(b)
—
 —
 1
 (6)
PECO1
 1
 3
 3
BGE(c)
1
 1
 3
 (3)
Pepco(d)
(8) 3
 (6) 26
DPL(e)
1
 2
 (6) 18
ACE(f)
(8) 2
 (6) 17
 Successor  Predecessor
Acquisition, Integration and Financing Costs(a)
Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016  January 1, 2016 to March 23, 2016
PHI(g)
$(15) $7
 $(17) $63
  $29
_________
(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)For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, incurred at ComEd that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.
(c)For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $6 million incurred at BGE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.
(d)For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at Pepco that have been deferred and recorded as a regulatory asset for anticipated recovery. For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $10 million incurred at Pepco that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.
(e)For the nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $3 million incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.
(f)For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at ACE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.
(g)For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $16 million and $24 million, respectively, incurred at PHI that have been deferred and recorded as a regulatory asset for anticipated recovery. For the Successor period March 24, 2016 to September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $13 million incurred at PHI that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

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

Pro-forma Impactpresentation 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.
 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,		 
Year Ended
December 31,
 
2016(a)
 
2016(a)
 
2016(b)
Total operating revenues$9,002
 $24,468
 $32,342
Net income attributable to common shareholders501
 1,346
 1,562
      
Basic earnings per share$0.54
 $1.46
 $1.69
Diluted earnings per share0.54
 1.45
 1.69
_________
(a)The amounts above include adjustments for non-recurring costs directly related to the merger of $20 million and $660 million for the three and nine months ended September 30, 2016, respectively, and intercompany revenue of $171 million for the nine months ended September 30, 2016.
(b)The amounts above include adjustments for non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for the year ended December 31, 2016.
Asset Divestitures (Exelon, Generation, PHI, Pepco and DPL)
EGTP, a Delaware limited liability company, was formed in 2014 with the purpose of financing a portfolio of assets comprised of two combined-cycle gas turbines (CCGTs) and three peaking/simple cycle facilities consisting of approximately 3.4 GW of generation capacity in ERCOT North and Houston Zones.  EGTP is an indirect wholly owned subsidiary of Exelon and Generation. Each of the aforementioned facilities are held through a wholly owned direct subsidiary of EGTP. EGTP also owns two equity method investments in shared facility companies. EGTP, its direct parent and its wholly owned subsidiaries secured a nonrecourse senior secured term loan facility, a revolving loan facility and certain commodity and interest rate swaps.
On May 2, 2017, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP, including the revolving credit facility. See Note 11 - Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP. As a result, as of September 30, 2017, certain EGTP assets and liabilities were classified as held for sale at their respective fair values less costs to sell and included in the other current assets and other current liabilities balances on Exelon's and Generation's Consolidated Balance Sheets. See Note 6 - Impairment of Long-Lived Assets for further information.
In July 2016, DPL completed the sale of a 9acre land parcel located on South Madison Street in Wilmington, DE, resulting in a pre-tax gain of approximately $4 million. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in the Exelon and PHI 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 11 - Debt and Credit Agreements for more information. In December 2016, Generation sold substantially all of the Upstream assets, see Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements in the Exelon 2016 Form 10-K for further information.
On May 2, 2016, Pepco completed the sale of the New York Avenue land parcel, located in 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 the Exelon and PHI Consolidated Statements of Operations and Comprehensive Income.

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

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.Registrant's revenue disaggregation.
5.6. Regulatory Matters (All Registrants)
Except for the matters noted below, the disclosures set forth in Note 3 -— Regulatory Matters of the Exelon 20162017 Form 10-K reflect, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.
Illinois Regulatory Matters
Tax Cuts and Jobs Act (Exelon and ComEd). On January 18, 2018, the ICC approved ComEd's petition filed on January 5, 2018 seeking approval to pass back to customers beginning February 1, 2018 $201 million in tax savings resulting from the enactment of the TCJA through a reduction in electric distribution rates. The amounts being passed back to customers reflect the benefit of lower income tax rates beginning January 1, 2018 and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. See Note 12 — Income Taxes for additional information on Corporate Tax Reform.
Electric Distribution Formula Rate (Exelon and ComEd). On April 13, 2017,16, 2018, ComEd filed its annual distribution formula rate update with the ICC pursuant to EIMA.ICC. The filing establishes the revenue requirement used to set the rates that will take effect in January 20182019 after the ICC’s review and approval, which is due by December 2017.2018. The revenue requirement requested is based on 20162017 actual costs plus projected 20172018 capital additions as well as an annual reconciliation of the revenue requirement in effect in 20162017 to the actual costs incurred that year. ComEd's 20172018 filing request includes a total increasedecrease to the revenue requirement of $96$23 million, reflecting an increasea decrease of $78$58 million for the initial revenue requirement for 20172018 and an increase of $18$35 million related to the annual reconciliation for 2016.2017. The revenue requirement for 2018 and the annual reconciliation for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.47%6.52% inclusive of an allowed ROE of 8.40%8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2016 provided for a weighted average debt and equity return on distribution rate base of 6.45% inclusive of an allowed ROE of 8.34%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 6 basis points. See table below for ComEd's regulatory assets associated with its electric distribution formula rate. For additional information on ComEd's distribution formula rate filings seeSee Note 3 — Regulatory Matters of the Exelon 20162017 Form 10-K.
On December 6, 2016, the ICC issued a final order approving the 201610-K for additional information on ComEd's distribution formula rate which included a total increase tofilings.
During the revenue requirement of $127 million, reflecting an increase of $134 million for the initial revenue requirement for 2016 and a decrease of $7 million related to the annual reconciliation for 2015. 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 had on the revenue requirement approved in this order. On March 22, 2017, the ICC issued an order approving ComEd's proposal to reduce the 2016 revenue requirement by $18 million, which was reflected in customer rates beginning in April 2017.
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 was effective June 1, 2017, and includes, among other provisions, (1) a Zero Emission Standard (ZES) providing compensation for certain nuclear-powered generating facilities, (2) an extension of and certain adjustments to ComEd’sfirst quarter 2018, ComEd revised its electric distribution formula rate, (3) new cumulative persistingas provided for by FEJA, to reduce the ROE collar calculation from plus or minus 50 basis points to 0 basis points beginning with the reconciliation filed in 2018 for the 2017 calendar year. This revision effectively offsets the favorable or unfavorable impacts to ComEd's electric distribution formula rate revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer. ComEd began reflecting the impacts of this change in its electric distribution formula rate regulatory asset in the first quarter 2017.
Energy Efficiency Formula Rate (Exelon and ComEd). On June 1, 2018, ComEd filed its 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 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.
On September 11, 2017, the ICC approved the IPA's ZES Procurement Plan filedformula rate update with the ICC on July 31, 2017. Bidders interestedICC. The filing establishes the 2019 application year revenue requirement used to set the rates that will take effect in participating inJanuary 2019 after the procurement process had 14 days following the ICC's approval of the plan to submit the required eligibility information and become qualified bidders. Generation’s Clinton and Quad Cities nuclear plants timely submitted the required eligibility information to the ICC and responded to follow up questions. Winning bidders will contract directly with Illinois utilities, including ComEd, for 10-year terms extending through May 31, 2027. 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 annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities will be required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017ICC’s review

78
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

- May 31,and approval, which is due by December 2018. The revenue requirement requested is based on 2017 actual costs plus projected 2018 and 2019 expenditures as well as an annual reconciliation of the revenue requirement in effect in 2017 to the actual costs incurred that year. ComEd's 2018 filing request includes a total increase to the revenue requirement of $39 million, reflecting an increase of $38 million for the initial revenue requirement for 2018 and an increase of $1 million related to the annual reconciliation for 2017. The revenue requirement for the 2019 application year provides for a weighted average debt and equity return on rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points.
Zero Emission Standard (Exelon, Generation and ComEd).Pursuant to FEJA, on January 25, 2018, the ZEC annual cost cap, is set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years,ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the IPA-approved targetedwinning bidders through the IPA's ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap will be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year.
On October 27, 2017, the IPA released the schedule forevent. Generation executed the ZEC procurement event indicating that contracts with zero emission facilities will be fully executed onIllinois utilities, including ComEd, effective January 30, 2018.26, 2018 and began recognizing revenue. Winning bidders will beare entitled to compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. ToDuring the extentthree months ended September 30, 2018, Generation is selected as a winning bidder,recognized revenue retroactiveof $61 million. During the nine months ended September 30, 2018, Generation recognized revenue of $315 million, of which $150 million related to the effective date of FEJA would be recognized in the period the contracts are executed. Upon the execution of the contracts, ComEd will record an associated obligation and expense for the procurement of ZEC's.ZECs generated from June 1, 2017 through December 31, 2017.
ComEd will recoverrecovers all costs associated with purchasing ZECs through a new rate rider that provides 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 with interest. ComEd began billing its retail customers under its new ZEC rate rider on June 1, 2017 and recorded a regulatory liability of $71 million as of September 30, 2017 for revenues recorded in advance of incurring expenses.2017.
On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. One lawsuit was filed by customers of ComEd, led by the Village of Old Mill Creek, and the other was brought by the EPSA and three other electric suppliers. Both lawsuits argueargued that the Illinois ZEC program willwould distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices and seeksought a permanent injunction preventing the implementation of the program. Exelon intervened and filed motions to dismiss in both lawsuits. In addition, on March 31, 2017, plaintiffs in both lawsuits filed motions for preliminary injunction with the court; the court stayed briefing on the motions for preliminary injunction until the resolution of the motions to dismiss.On July 14, 2017, the district court granted the motions to dismiss. On July 17, 2017, the plaintiffs appealed the decision to the U.S. Court of Appeals for the Seventh Circuit. Plaintiffs-Appellants initialOn February 21, 2018, the U.S. Court of Appeals for the Seventh Circuit issued an order inviting the Solicitor General to express the views of the United States on the matter. On May 29, 2018, the Solicitor General and FERC filed its brief wasin the U.S. Court of Appeals for the Seventh Circuit stating that the Illinois ZEC program does not violate federal law or interfere with FERC’s authority to regulate wholesale power markets. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. On September 27, 2018, the plaintiffs filed on August 28, 2017 anda request for a panel rehearing with the state’s and Exelon’s briefs were filed onU.S. Circuit Court of Appeals for the Seventh Circuit. On October 27, 2017. Reply briefs are due on December 12, 2017. Exelon cannot predict9, 2018, the outcomeU.S. Circuit Court of these lawsuits. It is possible that resolution of these matters could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, financial positions and cash flows.Appeals for the Seventh Circuit panel denied the request for rehearing.
See Note 7 -8 — Early Nuclear Plant Retirements for additional information regarding the economic challenges facing Generation’s Clinton and Quad Cities nuclear plants and the expected benefits of the ZES.
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 beginning with the reconciliation filed in 2018 for the 2017 calendar year. Elimination of the ROE collar effectively offsets the favorable or unfavorable impacts to ComEd's electric distribution formula rate revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer. ComEd began reflecting the impacts of this change in its electric distribution services costs regulatory asset in first quarter 2017. As of September 30, 2017, ComEd recorded an increase to its electric distribution services costs regulatory asset of approximately $21 million for this change.
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
Prior to FEJA, Illinois law required 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

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

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 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. On September 11, 2017, the ICC approved ComEd's 2018 - 2021 energy efficiency plan with minor modifications filed by ComEd with the ICC on June 30, 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.  Beginning January 1, 2018 through December 31, 2030, the return on equity that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd 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, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income 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 actual year-end energy efficiency regulatory asset balances less any related deferred income taxes. ComEd records 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.
ComEd cancelled its existing energy efficiency rate rider effective June 2, 2017. On August 1, 2017, ComEd filed with the ICC a reconciliation of revenues and costs incurred through the cancellation date. On August 30, 2017, the ICC approved ComEd's request, filed on August 1, 2017, to issue an $80 million credit on retail customers' bills in October 2017 for the majority of the over-recoveries with any final adjustment applicable to the over-recoveries to be billed or credited in the future. As of September 30, 2017, ComEd’s over-recoveries associated with its former energy efficiency rate rider were $33 million.
Initial Energy Efficiency Formula Rate Filing
On August 15, 2017, the ICC approved ComEd's new initial energy efficiency formula rate filed with the ICC on June 9, 2017 pursuant to FEJA. The filing establishes the formula under which energy efficiency rates will be calculated going forward and the revenue requirement used to set the initial rates for the period October 1, 2017 through December 31, 2017. The initial revenue requirement is based on projected costs and projected PJM capacity revenues for the period from June 1, 2017 through December 31, 2017, and projected year-end 2017 energy efficiency regulatory asset balances (less any related deferred income taxes). ComEd requested an initial decrease in revenue requirement of $7 million reflecting higher projected PJM capacity revenues compared to projected energy efficiency costs and provides for a weighted average debt and equity return of 6.47% inclusive of an allowed ROE of 8.40%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2017 will be included in ComEd’s 2018 energy efficiency formula rate filing and reflected in customer rates beginning January 2019. The approved energy efficiency formula rate also provides for revenue decoupling to effectively offset the favorable or unfavorable impacts to ComEd's energy efficiency formula rate revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer.
As of September 30, 2017, Exelon and ComEd recorded a regulatory asset of $78 million under the energy efficiency formula, reflecting $83 million of deferred energy efficiency costs partially offset by $5 million of over recoveries for the initial energy efficiency formula rate reconciliation.
2017 Energy Efficiency Formula Rate Filing
On September 11, 2017, the ICC approved ComEd's annual energy efficiency formula rate filed with the ICC on June 30, 2017 pursuant to FEJA. The filing establishes the revenue requirement used to set rates that will take effect

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

in January 2018. The revenue requirement for 2018 is based on projected 2018 energy efficiency costs and PJM capacity revenues, and year-end 2018 energy efficiency regulatory asset balances (less any related deferred income taxes). In its 2017 filing ComEd requested a total increase to the revenue requirement of $12 million and provides for a weighted average debt and equity return of 6.47% inclusive of an allowed ROE of 8.40%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2018 will be included in ComEd’s 2019 energy efficiency formula rate filing, and reflected in customer rates beginning January 2020.
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 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. FEJA also requires ComEd to use RPS collections to fund utility job training and workforce development programs in the amounts of $10 million in each of the years 2017, 2021, and 2025. ComEd recorded a $10 million and $20 million current and noncurrent liability, respectively, as of September 30, 2017 associated with this obligation. ComEd will recover all costs associated with purchasing RECs and funding utility job training and workforce development programs through a new RPS rate rider that provides 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 with interest. The first reconciliation and true-up for RECs will occur in 2021 and 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. ComEd began billing its retail customers under its new RPS rate rider on June 1, 2017 and recorded a related regulatory liability of $7 million as of September 30, 2017. ComEd also recorded a regulatory liability of $38 million for alternative compliance payments received from RES to purchase RECs on behalf of the RES in the future.
As of September 30, 2017, ComEd had received $45 million of over-recovered RPS costs and alternative compliance payments from RES, which are deposited into a separate interest bearing bank account pursuant to FEJA and are classified as Restricted cash on Exelon's and ComEd's Balance Sheets.
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 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.
On June 30, 2017, ComEd submitted 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. Such projections indicate that customer rate impacts will not exceed the limitations set by FEJA discussed below. 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

81
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

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 records 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 established under FEJA, ComEd records a regulatory asset or liability for any differences between revenues and incurred expenses.
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 September 30, 2017, 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 took 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.
Pennsylvania Regulatory Matters
2018 Pennsylvania Procurement ProceedingsElectric Distribution Base Rate Case (Exelon and PECO).Through PECO’s PAPUC approved DSP Programs, PECO procures electric supply for its default electric customers through PAPUC approved competitive procurements. 
On March 17, 2016,29, 2018, PECO filed its fourth DSP Programa request 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 December 8, 2016, the PAPUC approved the fourth DSP Program for the modified 48-month term and deferred CAP Shopping to another proceeding.  Office of Consumer Advocate and Low Income Advocates subsequently filed a Petition for Reconsideration and Clarification related to CAP Shopping. On March 16, 2017, the PAPUC granted reconsideration and consolidated the proceeding with the DSP II docket, which includes the pending CAP Shopping plan that would allow low-income CAP customers to purchase their generation supply from EGSs. PAPUC referred the consolidated proceedings to the Office of Administrative Law Judge for hearing and decision.
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 planningseeking approval to increase its investment for repairing, improving or replacing aging infrastructure.electric distribution base rates by $82 million beginning January 1, 2019. This requested amount includes the effect of an approximately $71 million reduction as a result of the ongoing annual tax savings beginning January 1, 2019 associated with the TCJA. The requested ROE was 10.95%.
On August 28, 2018, PECO and interested parties filed with the PAPUC approved PECO’sa petition for its proposedpartial settlement for an increase of $25 million in annual electric DSIC and LTIIP on October 22, 2015 for spending of $275 million over a 5 year period through 2020.  The PAPUC approved PECO's petition for its proposed modified gas LTIIP on June 14, 2017 for spending of $762 million over a 10 year period through 2022.distribution service revenues, which includes

82
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

the effect of an approximately $71 million reduction as a result of the ongoing annual tax savings beginning January 1, 2019 associated with the TCJA. No overall ROE was specified in the partial settlement. On October 18, 2018, the Administrative Law Judges issued a Recommended Decision to the PAPUC that the partial settlement be approved without modification. A final ruling from the PAPUC is expected before December 31, 2018, and if approved, the new electric distribution base rates will become effective on January 1, 2019.
Tax Cuts and Jobs Act (Exelon and PECO). On May 17, 2018, the PAPUC issued an order to all Pennsylvania utility companies, including PECO, requiring that the annual tax savings beginning on January 1, 2018 associated with TCJA be passed back to customers. The order directs Pennsylvania utility companies without an existing base rate case, including PECO’s gas distribution business, to start passing back the savings from January 1, 2018 onward through a negative surcharge mechanism to be effective on July 1, 2018. Pursuant to the May 17, 2018 order, PECO filed a negative surcharge mechanism and began on July 1, 2018, to return an estimated $4 million in annual 2018 tax savings to its natural gas distribution customers. For Pennsylvania utility companies with existing base rate cases, including PECO’s electric distribution base rate case, the timing of when and how to pass the annual TCJA savings to customers will be resolved through the base rate case proceeding.
As part of the rate case filing referenced above, PECO is seeking approval to pass back to electric distribution customers $68 million in 2018 TCJA tax savings of which the majority will be passed back in January 2019 with the remainder refunded over the balance of the year. The TCJA tax savings would be an additional offset to the proposed increase to its electric distribution rates. The amounts being proposed to be passed back to customers reflect the respective annual benefits of lower income tax rates established upon enactment of the TCJA.
See Note 12 — Income Taxes for additional information on Corporate Tax Reform and the table below for regulatory liabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer rates.
Maryland Regulatory Matters
Tax Cuts and Jobs Act (Exelon, BGE, PHI, Pepco and DPL).  On January 12, 2018, the MDPSC issued an order that directed each of BGE, Pepco and DPL to track the impacts of the TCJA beginning January 1, 2018 and file by February 15, 2018 how and when they expect to pass through such impacts to their customers.
On January 31, 2018, the MDPSC approved BGE's petition to pass back to customers $103 million in ongoing annual tax savings resulting from the enactment of the TCJA through a reduction in distribution base rates beginning February 1, 2018, of which $72 million and $31 million were related to electric and natural gas, respectively. The amounts being passed back to customers reflect the ongoing annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. BGE's natural gas distribution rate case filing in June 2018 included a request to provide to customers the natural gas portion of the January 2018 TCJA savings over a 5-year period.
On April 20, 2018, Pepco entered into a settlement agreement with several parties to resolve all issues in its pending electric distribution base rate case, including the treatment of the annual ongoing TCJA tax savings as well as the TCJA tax savings from January 1, 2018 through the expected effective date of the rate change. On May 31, 2018, the MDPSC issued an order approving the settlement agreement with an effective date of June 1, 2018. See discussion below for additional information.
On February 9, 2018, DPL filed with the MDPSC seeking approval to pass back to customers $13 million in ongoing annual TCJA tax savings through a reduction in electric distribution base rates beginning in 2018. On April 18, 2018, the MDPSC approved a settlement agreement to pass back to

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

customers $14 million in ongoing annual TCJA tax savings through a reduction in electric distribution base rates beginning April 20, 2018. The amounts being passed back to customers reflect the ongoing annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. In addition, the MDPSC separately ordered DPL to provide a one-time bill credit to customers of $2 million in June 2018 representing the TCJA tax savings from January 1, 2018 through March 31, 2018.
See Note 12 — Income Taxes for additional information on Corporate Tax Reform and the table below for regulatory liabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer rates.
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). On December 1, 2017 (and as amended on January 22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated surcharge, subject to BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and the associated surcharge will be effective in rates beginning in January 2019. The new five-year plan calls for capital expenditures over the 2019-2023 timeframe of $732 million, with an associated revenue requirement of $200 million.
2018 Maryland Natural Gas Distribution Base Rates (Exelon and BGE). On June 8, 2018, and as amended on August 24, 2018 and October 12, 2018, BGE filed an application with the MDPSC to increase natural gas revenues by $61 million, reflecting a requested ROE of 10.5%. BGE expects a decision in the first quarter of 2019 but cannot predict how much of the requested increase the MDPSC will approve.
2018 Maryland Electric Distribution Base Rates (Exelon, PHI and Pepco).On March 24, 2017,January 2, 2018, Pepco filed an application with the MDPSC to increase its annual electric distribution base rates by $69$41 million, which was updated to $67 million on August 24, 2017, reflecting a requested ROE of 10.1%. The application included a request forOn February 5, 2018, Pepco filed with the MDPSC an income tax adjustmentupdate to its current distribution base rate case to reflect full normalization of removal costs associated with pre-1981 property, which accounted for $18$31 million ofin ongoing annual TCJA tax savings, thereby reducing the requested increase.annual base rate increase to $11 million. On October 20, 2017,March 8, 2018, Pepco filed with the MDPSC approved an increase in Pepcoa subsequent update to its electric distribution base rate case, which further reduced the requested annual base rate increase to $3 million. On April 20, 2018, Pepco entered into a settlement agreement with several parties to resolve all issues in the rate case and filed the settlement agreement with the MDPSC. The settlement agreement provides for a net decrease to annual electric distribution base rates of $34$15 million, reflectingwhich includes annual ongoing TCJA tax savings, and reflects a ROE of 9.5%. In addition, the settlement agreement separately provides a one-time bill credit to customers of approximately $10 million representing the TCJA tax savings from January 1, 2018 through the expected rate effective date of June 1, 2018. On October 27, 2017,May 31, 2018, the MDPSC issued an errata order revisingapproving the approved increasesettlement agreement with an effective date of June 1, 2018. Pepco issued the $10 million to customers in Pepco electric distribution rates to $32 million. The errata order corrected a number of computational errors in the original order but did not alter any of the findings.  The new rates became effective for services rendered on or after October 20, 2017.  In its decision, the MDPSC denied Pepco’s request regarding the income tax adjustment without prejudice to Pepco filing another similar proposal with additional information.  Requests for rehearing are due November 20, 2017.July 2018.
2017 Maryland Electric Distribution Base Rates (Exelon, PHI and DPL).On July 14, 2017, DPL filed an application with the MDPSC to increase its annual electric distribution base rates by $27 million, which was updated to $22$19 million on September 28,November 16, 2017, reflecting a requested ROE of 10.1%. On December 18, 2017, a settlement agreement was filed with the MDPSC wherein DPL expectswill be granted a decision inbase rate increase of $13 million, and a ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs. On February 9, 2018, the matter inMDPSC approved the firstsettlement agreement and the new rates became effective.
In the second quarter of 2018, but cannot predict how muchDPL discovered a rate design issue in Maryland such that the current rates were not sufficient to collect the full amount of the requested$13 million revenue increase agreed to by the MDPSC will approve.
2016 Maryland Electric Distribution Rates (Exelon, PHI and DPL). parties in the recent settlement. On February 15, 2017,September 5, 2018, the MDPSC approved an increase in DPL electric distribution rates of $38 million reflectingDPL’s proposed revisions to resolve the rate design issue on a ROE of 9.6%.  The new rates becameprospective basis, effective for services rendered on or after February 15, 2017.  The MDPSC also denied DPL’s request to continue its Grid Resiliency Program, through which DPL proposed to invest $5 million a year for two years to improve priority feeders and install single-phase reclosing fuse technology. The final order did not result in the recognition of any incremental regulatory assets or liabilities.
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's positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs.  The order also grants BGE a return on the SOS.  The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case. 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. On February 22, 2017, the residential consumer advocate filed an appeal of the MDPSC's orders with the Circuit Court for Baltimore City. The residential consumer advocate filed its Memorandum on Appeal on June 5, 2017 and subsequent Reply Memoranda were filed by BGE and the MDPSC on July 7, 2017 and July 12, 2017, respectively. On August 7, 2017, following oral argument by the parties, a decision was issued from the Circuit Court affirming the decision of the MDPSC. On September 5, 2017, the residential consumer advocate filed an appeal of the Circuit Court's decision to the Maryland Court of Special Appeals. BGE cannot predict the outcome of this appeal.
Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and natural gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of September 30, 2017 and December 31, 2016, the balance of BGE's regulatory asset was $219 million and $230 million, respectively, representing incremental program deployment costs. The current quarter balance of $219 million consists of three major components, including $133 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 approval became effective June 2016. The balance as of September 30, 2017 reflects the impact of the cost disallowances and adjustments in BGE's 2015 electric and natural gas distribution rate case. The incremental deployment costs for the AMI program and the non-AMI meter components of the regulatory asset are being recovered through rates and amortized to expense2018.

83
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

over a 10 year period, while the post-test year incremental program deployment costs have not yet been approved for recovery by the MDPSC. A return on the regulatory asset is currently included in rates, except for the $54 million portion representing the unamortized cost of the retired non-AMI meters and a $32 million portion related to post-test year incremental program deployment costs.
As a combined result of the MDPSC orders in BGE's 2015 electric and natural gas distribution rate case, BGE recorded a $52 million charge in June 2016 to Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income reducing certain regulatory assets and other long-lived assets and reclassified $56 million of non-AMI plant costs from Property, plant and equipment, net to Regulatory assets on Exelon's and BGE's Consolidated Balance Sheets. For further information, see Note 3 - Regulatory Matters of the Exelon 2016 Form 10-K.
Delaware Regulatory Matters
Tax Cuts and Jobs Act (Exelon, PHI and DPL).  On January 16, 2018, the DPSC opened a docket indicating that DPL’s TCJA tax savings would be addressed in its pending rate cases. See discussion below for further information on the proposed treatment of the TCJA tax savings in DPL’s pending electric and natural gas distribution base rate cases.
2017 Delaware Electric and Natural Gas Distribution Base Rates (Exelon, PHI and DPL). On August 17, 2017 (as updated on February 9, 2018 to reflect $19 million and $7 million of ongoing annual TCJA tax savings for electric and natural gas, respectively), DPL filed applications with the DPSC to increase its annual electric and natural gas distribution base rates by $24$12 million which was updated to $31 million on October 18, 2017, and $13$4 million, respectively, reflecting a requested ROE of 10.1%. DPL expects a decision inThe ongoing annual TCJA tax savings reflect the electric proceedingongoing annual benefit of lower income tax rates and the gas proceeding in the third quartersettlement of 2018, but cannot predict how mucha portion of deferred income tax regulatory liabilities established upon enactment of the requested rate increasesTCJA. Of the DPSC will approve. While the DPSC is not required to issue a decision on the application within a specified period of time, Delaware law allows DPL to put into effect $2.5 million of the rate increase two months after filing the application and the entire requested rate increase seven months after filing, subject to a cap and a refund obligation based on the final DPSC order.  On October 24, 2017, the Staff of the DPSC and the Public Advocate filed a joint motion to dismiss DPL's electric distribution base rate application without prejudice to refiling, arguing that the amount of the requested increase to $31 million required additional time to review and additional public notice.  The DPSC is expected to decide at its meeting on November 9, 2017. DPL cannot predict the outcome of this matter.
2016 Electric and Natural Gas Distribution Rates (Exelon, PHI and DPL). On May 17, 2016, DPL filed applications with the DPSC to increase its annualproposed electric and natural gas distribution base rates by $63 million, which was updated to $60 million on March 8, 2017, and $22 million, respectively, reflecting a requested ROE of 10.6%. Delaware law allowed DPL to put into effectrate increases, $2.5 million of each ofwere put into effect in the rate increases effective July 16, 2016. On December 17, 2016, the DPSC approved an additional $30 million in electric distribution ratesfourth quarter 2017 and an additional $10$3 million and $1 million, respectively, were put into effect in natural gas distribution rates effective December 17, 2016,the first quarter 2018, all of which are subject to refund based on the final DPSC orders.order.
On March 8, 2017,June 27, 2018, DPL entered into a settlement agreement with all active parties in the Division of the Public Advocate, Delaware Electric Users Group and the DPSC Staff inproceeding related to its pending electric distribution base rate proceeding, whichcase. The settlement agreement provides for an increase in DPLa net decrease to annual electric distribution base rates of $31.5$7 million, reflectingwhich includes annual ongoing TCJA tax savings, and reflects a ROE of 9.7% compared. In addition, the settlement agreement separately provides a one-time bill credit to customers of approximately $3 million representing the $32 million increase previouslyTCJA tax savings from February 1, 2018 through March 17, 2018, when full interim rates were put into effect. On May 23, 2017,August 21, 2018, the DPSC issued an order approvingapproved the settlement agreement withas filed. DPL expects to issue the new rates effective June 1, 2017. Pursuant$3 million to customers in the settlement agreement, no refundfourth quarter of the interim rates put into effect on July 16, 2016 and December 17, 2016 (as discussed above) is required.2018.
On April 6, 2017,September 7, 2018 (as amended and restated on October 2, 2018), DPL entered into a partial settlement agreement with the Division of the Public Advocate and the DPSC Staffseveral parties in its naturalpending gas distribution base rate case proceeding whichthat provides for an increase in DPLa net decrease to annual natural gas distribution base rates of $4.9$4 million, reflectingwhich includes annual ongoing TCJA tax savings, and reflects a ROE of 9.7%. The settlement agreement also provides that DPL will refund amounts collected under the temporary rates effective July 16, 2016 and December 17, 2016 (as discussed above) in excess of the $4.9 million, and that the new rates will be effective within thirty days of DPSC approval of the settlement agreement. On June 6, 2017, the DPSC issued an order approvingIn addition, the settlement agreement withseparately provides a one-time bill credit to customers of approximately $1 million, which includes the newTCJA tax savings from February 1, 2018 through March 17, 2018, when full interim rates effective July 1, 2017. Pursuant towere put into effect. DPL expects a decision on the settlement agreement a rate refund plus interestin the fourth quarter of approximately $5 million was issued to customers beginning in August 20172018 but cannot predict if the DPSC will approve the settlement agreement as filed.
See Note 12 — Income Taxes for which aadditional information on Corporate Tax Reform and the table below for regulatory liability has been recorded as of September 30, 2017. This is a one-time refund and was included onliabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer bills from mid-August through mid-September.rates.
District of Columbia Regulatory Matters
2016 Electric Distribution RatesTax Cuts and Jobs Act (Exelon, PHI and Pepco).On June 30, 2016,January 23, 2018, the DCPSC opened a rate proceeding directing Pepco to track the impacts of the TCJA beginning January 1, 2018 and file its plan to reduce the current revenue requirement by customer class by February 12, 2018. The DCPSC stated it will address the impact of the TCJA on future rates within Pepco's pending electric distribution base rate case discussed below.
On February 6, 2018, Pepco filed an application with the DCPSC seeking approval to increase itspass back to customers $39 million in ongoing annual tax savings resulting from the enactment of the TCJA through a reduction to existing electric distribution base rates by $86 million, which was updatedbeginning in 2018. On April 17, 2018, Pepco entered into a settlement agreement with several parties to $77 million on February 1, 2017, reflecting a requested ROE of 10.6%.
On July 25, 2017, the DCPSC approved an increaseresolve all issues in Pepcoits pending electric distribution base ratesrate case, including the treatment of $37 million reflecting a ROEthe annual ongoing TCJA tax savings as well as the TCJA tax savings from January 1, 2018 through the expected effective date of 9.5%. The new rates became effective for services rendered on or afterthe rate change. On August 15, 2017.  In its9,

84
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

decision,2018, the DCPSC ordered thatapproved the $26 million customer rate credit created as a resultsettlement agreement with an effective date of the Exelon and PHI merger will be provided primarily to residential customers and some small commercial customers to offset the impact of this increase until that amount has been exhausted, which is expected to take approximately two years. Additionally, the Commission is holding approximately $6 million to $7 million of the customer rate creditAugust 13, 2018. See discussion below for use toward a possible new class of customers for certain senior citizens and disabled persons.  The DCPSC also held that Pepco's bill stabilization adjustment, which decouples distribution revenues from utility customers from the amount of electricity delivered, will continue to be in place and that no refund of previously collected funds is required.  Several parties filed requests that the DCPSC reconsider the order on various issues, and on October 6, 2017, the Commission issued an order denying each of the requests.additional information.
2017 District of Columbia Power Line Undergrounding InitiativeElectric Distribution Base Rates (Exelon, PHI and Pepco). The District of Columbia government enacted  On December 19, 2017 (and updated on an emergency basis (effective May 17, 2017) and thereafter on a permanent basis (effective July 11, 2017) legislation to amend the Electric Company Infrastructure Improvement Financing Act of 2014 (as amended) (the Infrastructure Improvement Financing Act) to authorize the District of Columbia Power Line Undergrounding (DC PLUG) initiative, a projected six year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded byFebruary 9, 2018), Pepco and $250 million funded by the District of Columbia.
The $250 million of project costs funded by Pepco will be recovered through a volumetric surcharge on the electric bill of substantially all of Pepco's customers in the District of Columbia. Pepco will earn a return on these project costs.
The $250 million of project costs funded by the District of Columbia will come from two sources. Project costs of $187.5 million will be funded through a charge assessed on Pepco by the District of Columbia; Pepco will recover this charge from customers through a volumetric distribution rider. The remaining costs up to $62.5 million are to be funded by the existing capital projects program of the District Department of Transportation (DDOT). Ownership and responsibility for the operation and maintenance of all the assets funded by the District of Columbia will be transferred to Pepco for a nominal amount upon completion. Pepco will not recover or earn a return on the cost of the assets transferred to it by the District of Columbia.
In accordance with the Infrastructure Improvement Financing Act, Pepco filed an application for approval of the first two-year portion of the DC PLUG initiative (the First Biennial Plan) on July 3, 2017. After the initial application, Pepco will be required to make two updated applications, one every two years until the project is completed. Pepco anticipates that the DCPSC will issue an order approving the First Biennial Plan in early November 2017. Upon the issuance of a DCPSC order approving the First Biennial Plan, Pepco will become obligated to pay $187.5 million to the District of Columbia over the six year project term, at which time it will record an obligation and offsetting regulatory asset.
New Jersey Regulatory Matters
New Jersey Consolidated Tax Adjustment (Exelon, PHI and ACE). The Consolidated Tax Adjustment (CTA) is a New Jersey ratemaking policy that requires utilities that are part of a consolidated tax group to share with customers the tax benefits that came from losses at unregulated affiliates through a reduction in rate base. In 2013, the NJBPU opened a generic proceeding to review the policy. In 2014, the NJBPU issued a decision which retained the CTA, but in a highly modified format that significantly reduced the impact of the CTA to ACE. On September 18, 2017, the Appellate Division of the Superior Court of New Jersey reversed the NJBPU’s decision in adopting the revised CTA policy and held that NJBPU’s actions related to the CTA constituted a rulemaking that should have been undertaken pursuant to the requirements of the Administrative Procedures Act. The Court did not address the merits of the CTA methodology itself. No party filed an appeal of the Court’s decision, and the NJBPU is expected to conduct further proceedings. If the NJBPU were to apply the CTA in its unmodified form, it could have a material prospective impact to ACE through a reduction in rate base in future rate cases.
2017 Electric Distribution Rates (Exelon, PHI and ACE). On March 30, 2017, ACE filed an application with the NJBPUDCPSC to increase its annual electric distribution base rates by $70$66 million, (before New Jersey sales and use tax), which was updated to $73 million on July 14, 2017, reflecting a requested ROE of 10.1%. The application also requests approval of a rate surcharge mechanism called the “System Renewal Recovery Charge,” which would permit more timely recovery of certain costs associated with reliability and system renewal-related capital investments. 
On September 8, 2017, ACEApril 17, 2018, Pepco entered into a settlement agreement with several parties to resolve both the pending electric distribution base rate case and the $39 million rate reduction request in the TCJA proceeding discussed above and filed the settlement agreement with the DCPSC. The settlement agreement provides for a net decrease to annual electric distribution rates of $24 million, which includes annual ongoing TCJA tax savings, and reflects a ROE of 9.525%. On August 9, 2018, the DCPSC approved the settlement agreement with an effective date of August 13, 2018. In addition, the settlement agreement separately provides for a one-time bill credit to customers of approximately $19 million representing the TCJA benefits for the period January 1, 2018 through the expected rate effective date of July 1, 2018. As rates did not go into effect until August 13, 2018, on September 7, 2018, Pepco submitted an updated filing for a one-time bill credit to customers of approximately $20 million, and an increase of $4 million to the customer base rate credit established in connection with the merger between Exelon and PHI for residential customers, representing the TCJA benefits for the period January 1, 2018 through August 12, 2018. Following the expiration of the comment period with no objections filed, Pepco issued the $20 million to customers in September 2018.
See Note 12 — Income Taxes for additional information on Corporate Tax Reform and the table below for regulatory liabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer rates.
New Jersey Regulatory Matters
Tax Cuts and Jobs Act (Exelon, PHI and ACE). On January 31, 2018, the NJBPU staff, theissued an order mandating that New Jersey Division of Rate Counsel and Wal-Mart Stores, Inc.utility companies, including ACE, pass any economic benefit from the TCJA to rate payers. The order directed New Jersey utility companies to file by March 2, 2018 proposed tariff sheets reflecting TCJA benefits, with new rates to be implemented in itstwo phases. In addition, the NJBPU directed New Jersey utility companies to file by March 2, 2018 a Petition with the NJBPU outlining how they propose to refund any over-collection associated with revised rates not being in place from January 1, 2018 through March 31, 2018, with interest.
On March 2, 2018, ACE filed with the NJBPU seeking approval to pass back to customers $23 million in ongoing annual TCJA tax savings through a reduction in electric distribution rate proceeding,base rates beginning in 2018. The amounts being passed back to customers would reflect the ongoing annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. On March 26, 2018, the NJBPU issued an order accepting ACE’s proposed bill reduction related to the lower income tax rates. A portion of the annual decrease in electric distribution base rates totaling approximately $13 million was effective as of April 1, 2018, but considered interim. On August 29, 2018, the NJBPU issued an order approving final rates with an effective date of September 8, 2018, which providesreflects the full amount of ACE’s proposed $23 million reduction, including a one-time bill credit to customers of approximately $6 million representing the TCJA tax savings from January 1, 2018 through June 30, 2018. ACE expects to issue the $6 million to customers in the fourth quarter of 2018. ACE's treatment of the TCJA tax savings for an increasethe period July 1, 2018 through the effective date of the final rates is the subject of ongoing discussions, and ACE anticipates that the NJBPU will issue a clarifying order in the fourth quarter of 2018.
See Note 12 — Income Taxes for additional information on Corporate Tax Reform and the table below for regulatory liabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer rates.

85
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

in ACE annual electric distribution base rates of $43 million (before New Jersey sales and use tax) reflecting a ROE of 9.6%.  In addition, pursuant to the settlement agreement, ACE agreed to withdraw its request for approval of a System Renewal Recovery Charge without prejudice to its right to refile.  On September 22, 2017, the NJBPU issued an order approving the settlement agreement, with the new rates effective on October 1, 2017.
2016 Electric Distribution RatesInfrastructure Investment Program Filing (Exelon, PHI and ACE).On August 24, 2016,February 28, 2018, ACE filed with the NJBPU issued an order approvingthe company’s Infrastructure Investment Program (IIP) proposing to seek recovery of a stipulationseries of settlement amonginvestments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. ACE currently expects a decision in this matter in the New Jersey Divisionfirst quarter of Rate Counsel, NJBPU Staff and Unimin Corporation, which, among other things, provided that a determination on ACE's grid resiliency program, PowerAhead, would be separated into a phase II of the rate proceeding and decided at a later date. PowerAhead includes capital investments to enhance the resiliency of the system through improvements focused on improving the distribution system's ability to withstand major storm events. A stipulation of settlement with respect to the PowerAhead program (the PowerAhead Stipulation) was approved by2019 but cannot predict if the NJBPU on May 31, 2017. As adopted,will approve the PowerAhead program includes an approved investment level of $79 million to be recovered through the cost recovery mechanism described in the PowerAhead Stipulation. The NJBPU order adopting the PowerAhead Stipulation was effective on June 10, 2017.application as filed.
Update and Reconciliation of Certain Under-RecoveredOver and Under Recovered Balances (Exelon, PHI and ACE).On February 1, 2017,5, 2018, ACE submitted its 20172018 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 decrease of approximately $29$19 million, (revised to approximately $32 million in April 2017, based upon an update for actuals through March 2017), including New Jersey sales and use tax. On May 31, 2017,22, 2018, the NJBPU approved a stipulation of settlement entered into by theamong certain interested parties providing for an overall annual rate decrease of approximately $32$33 million, effective June 1, 2017.2018. The rate decrease was placed into effect provisionally, subject to a review by the NJBPU and the Division of Rate Counsel of the final underlying costs for reasonableness and prudence. This rate decrease will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism. The matter is pending at the NJBPU.
New Jersey Clean Energy Legislation (Exelon, Generation and ACE). On May 23, 2018, the Governor of New Jersey signed new legislation, which became effective immediately, that establishes and modifies New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards. The new legislation expands the state's renewable portfolio standard to require that 50% of electric generation sold be from renewable energy sources by 2030; modifies the New Jersey solar renewable energy portfolio standard to require that 5.1% of electric generation sold in New Jersey be from solar electric power by 2021, lowers the solar alternative compliance payment amount starting in 2019 and requires the NJBPU to adopt rules to replace the current solar renewable energy credit program; and requires the NJBPU to increase its offshore wind energy credit program to 3,500 MW. The new legislation further imposes an energy efficiency standard that each electric public utility will be required to reduce annual usage by 2% and provides for utilities to annually file for recovery of the costs of the programs, including the revenue impact of sales losses resulting from the programs. The NJBPU is required to initiate a study to determine the savings targets for each public utility, to adopt other rules regarding the programs, and to approve energy efficiency and peak demand reduction programs for each utility. The new legislation also requires the NJBPU to conduct an energy storage analysis including the potential costs and benefits and to initiate a proceeding to establish a goal of achieving 2,000 MW of energy storage by 2030; requires the utilities to conduct a study on voltage optimization on their distribution system; and requires the NJBPU to establish a community solar program to permit customers to participate in a solar project that is not located on the customer’s property.
On the same day, the Governor of New Jersey also signed new legislation, which became effective immediately, that will establish a ZEC program providing compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. PSEG’s Salem nuclear plant is expected to apply for approval to participate in the ZEC program. Under the new legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. The NJBPU has 180 days from the effective date to establish procedures for implementation of the ZEC program and 330 days from the effective date to determine which nuclear power plants are selected to receive ZECs under the program. Selected nuclear plants will receive ZEC payments for each energy year (12-

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

month period from June 1 through May 31) within 90 days after the completion of such energy year. The quantity of ZECs issued will be determined based on the greater of 40% of the total number of MWh of electricity distributed by the public electric distribution utilities in New Jersey in the prior year, or the total number of MWh of electricity generated in the prior year by the selected nuclear power plants. The ZEC price is approximately $10 per MWh during the first 3-year eligibility period. For eligibility periods following the first 3-year eligibility period, the NJBPU has discretion to reduce the ZEC price. Electric distribution utilities in New Jersey, including ACE, will be authorized to collect from retail distribution customers through a non-bypassable charge all costs associated with the utility’s procurement of the ZECs. On August 29, 2018, the NJBPU issued an order opening a proceeding in which stakeholders can provide input on implementation of the ZEC program. See Note 8 - Early Plant Retirements for additional information on New Jersey’s ZEC program potential impacts to PSEG’s Salem nuclear plant.
2018 New Jersey Electric Distribution Base Rates (Exelon, PHI and ACE). On June 15, 2018, ACE submitted an application with the NJBPU to increase its annual electric distribution base rates by $99.7 million (before New Jersey sales and use tax), based upon a requested ROE of 10.1%. Included in the $99.7 million request is $40 million of higher depreciation expense related to ACE's updated depreciation study. On July 25, 2018, the NJBPU dismissed ACE’s base rate case due to the number of forecasted months included in the twelve month test period. Historically, ACE and other New Jersey utilities have filed distribution base rate cases with a similar number of forecasted months in the test period.
On August 21, 2018, ACE refiled its application with the NJBPU, requesting an increase to its electric distribution rates of $109 million (before New Jersey sales and use tax), reflecting a requested ROE of 10.1%. Included in the $109 million request is $40 million of higher depreciation expense related to ACE's updated depreciation study. ACE currently expects a decision in this matter in the third quarter of 2019 but cannot predict if the NJBPU will approve the application as filed.
New York Regulatory Matters
New York Clean Energy Standard (Exelon and Generation).On August 1, 2016, the New York Public Service Commission (NYPSC)NYPSC issued an order establishing the New York CES, a component of which is thea 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
On October 19, 2016, a coalition of ZECs equivalent to its load ratio sharefossil-generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions 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 three plants eligible forU.S. Constitution; specifically, that the ZEC program: the FitzPatrick, Ginna,program interferes with FERC’s jurisdiction over wholesale rates and Nine Mile Point nuclear facilities. As issued, the order also provided that the durationit discriminates against out of the program beyond the first tranche was conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018.state competitors. On November 18,December 9, 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. On March 31, 2017, Generation closed on the acquisition of FitzPatrick. Generation is currently recognizing revenue for the sale of New York ZECs in the month following generation when the ZECs are transferred to NYSERDA. For the three and nine months ended September 30, 2017, Generation has recognized $118 million and $191 million of ZEC revenue.
Several parties filed with the NYPSC requests for rehearing or reconsideration of the New York CES. Generation and CENG filed a motion to intervene in the case and to dismiss the lawsuit. The State also filed a requestmotion to dismiss. On July 25, 2017, the court granted both motions to dismiss. On August 24, 2017, the plaintiff appealed the decision to the U.S. Court of Appeals for clarification, or in the alternative limited rehearing, thatSecond Circuit. On September 27, 2018, the condition limitingU.S. Court of Appeals for the durationSecond Circuit affirmed the lower court's dismissal of the program beyondcomplaint against the first tranche be limited to the eligibilityZEC program.
In addition, on November 30, 2016, a group of the FitzPatrick plant onlyparties, including certain environmental groups and have no

86
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollarsindividuals, filed a Petition in millions, except per share data, unless otherwise noted)

bearing on Ginna or Nine Mile Point’s eligibility for the full 12-year duration. On December 15, 2016, the NYPSC approved Generation’s and CENG's petition to clarify this condition and denied all petitions for rehearing of the New York CES. Parties had until mid-April to appeal to New York State court the denials of the requests for rehearing. A Petition seeking to invalidate the ZEC programprogram. The Petition, which was filed in New York State court by certain environmental groups and other parties on November 30, 2016, and amended on January 13, 2017, arguingargued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act (SAPA) when adopting the ZEC program. On February 15, 2017, Generation and CENG filed a motion to dismiss the state court action. The NYPSC also filed a motion to dismiss the state court action. On March 24, 2017, the plaintiffs filed a memorandum of law opposing the motions to dismiss, and Generation and CENG filed a reply brief on April 28, 2017. Oral argument was held on June 19, 2017. The motions to dismiss are pending.
On October 19, 2016, a coalition of fossil generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors.  On December 9, 2016, Generation and CENG filed a motion to intervene in the case and to dismiss the lawsuit. The State also filed a motion to dismiss. Oral argument was held on March 29, 2017. On July 25, 2017, the court granted both motions to dismiss. On August 24, 2017, plaintiffs appealed the decision to the Second Circuit. Plaintiffs-Appellants’ initial brief was filed on October 13, 2017. The state’s and Exelon’s briefs are due on November 17, 2017. Reply briefs are due on December 1, 2017.
Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 7 - Early Nuclear Plant Retirements for additional information relative to Ginna and Nine Mile Point. See Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation's 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 with a term expiring on March 31, 2017. In April 2016, Generation began recognizing revenue based on the final approved pricing contained in the RSSA and also recognized a one-time revenue adjustment of 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 was removed from Generation’s results of operations as a result of the noncontrolling interests in CENG.
The RSSA required Ginna to continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the New York CES. As stated previously, on November 18, 2016 the required contract with NYSERDA was executed by Generation and CENG for Ginna. Upon the expiry of the RSSA on March 31, 2017, Ginna was required to make refund payments of $20 million to RG&E related to capital expenditures. Ginna paid RG&E the $20 million in June 2017. Additionally, the provisions of the RSSA provided for a one-time payment of $12 million to be paid from RG&E to Ginna at the end of the contract. This $12 million was recognized in revenue as of March 31, 2017. RG&E paid the $12 million to Ginna in May 2017. Subject to prevailing over any administrative or legal challenges, it is expected the New York CES will allow Ginna to continue to operate through the end of its current operating license in 2029. See Note 7-Early Nuclear Plant Retirements for further information regarding the impacts of a decision to early retire one or more nuclear plants.

87
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

argument was held on June 19, 2017. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. The case is now proceeding to summary judgment with the full record. Exelon’s and the state’s answers and briefs were filed on March 30, 2018. Plaintiffs’ responses were due on May 11, 2018; however, on April 17, 2018, the plaintiffs filed an order to show cause seeking production of additional documents, including confidential financial information. Exelon and the state filed in opposition to the order to show cause. On July 18, 2018, the court denied the order to show cause and ordered the parties to provide the court with an agreed upon final schedule for the remaining brief. Negotiations over the schedule for the remaining briefing have not yet been finalized. After briefing is completed, the court will decide whether or not to set the case for hearing.
Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 8 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.
Federal Regulatory Matters
Tax Cuts and Jobs Act and Transmission-Related Income Tax Regulatory Assets (Exelon and the Utility Registrants). Pursuant to their respective transmission formula rates, ComEd, PECO, BGE, Pepco, DPL and ACE began passing back to customers on June 1, 2018, the benefit of lower income tax rates effective January 1, 2018. ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s transmission formula rates currently do not provide for the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA.
On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. FERC’s rejection order focused on the lack of timeliness of BGE’s request to recover amounts that would have been previously amortized but indicated that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement. Based on FERC’s order, management of each company concluded that the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery was no longer probable of recovery. As a result, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE recorded charges to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017, reducing their associated transmission-related income tax regulatory assets. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula and, thus, are not impacted by BGE’s November 16, 2017 FERC order. See below for additional information regarding PECO's transmission formula rate filing.
On December 18, 2017, BGE filed for clarification and rehearing of FERC’s order, still seeking full recovery of its existing transmission-related income tax regulatory asset amounts, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. On February 27, 2018 (and updated on March 26, 2018), BGE submitted a letter to FERC advising that the lower federal corporate income tax rate effective January 1, 2018 provided for in TCJA will be reflected in BGE’s annual formula rate update effective June 1, 2018, but that the deferred income tax benefits will not be passed back to customers unless BGE’s

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

formula rate is revised to provide for pass back and recovery of transmission-related income tax-related regulatory liabilities and assets.
On February 23, 2018 (and as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to facilitate passing back to customers ongoing annual TCJA tax savings and to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.
On September 7, 2018, FERC issued orders rejecting BGE’s December 18, 2017 request for rehearing and clarification and ComEd's, Pepco's, DPL's and ACE's February 23, 2018 (as amended on July 9, 2018) filings, again citing the lack of timeliness of the requests to recover amounts that would have been previously amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement. The orders did not address the remittance of TCJA transmission-related income tax regulatory liabilities, but rather referenced FERC’s separate Notice of Inquiry of such amounts issued on March 15, 2018.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted new filings to recover ongoing non-TCJA amortization amounts and refund TCJA transmission-related income tax regulatory liabilities for the prospective period starting on October 1, 2018 but cannot predict the outcome of these FERC proceedings. If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be up to approximately $73 million, $51 million, $13 million, $9 million, $3 million, $5 million and $1 million, respectively, as of September 30, 2018.
On October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order, still seeking full recovery of their existing transmission-related income tax regulatory asset amounts, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. ComEd, Pepco, DPL, and ACE cannot predict the outcome of this rehearing request. BGE has 60 days from the FERC September 7, 2018 order to file a petition for review in the federal court of appeals.

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).The following total increases/(decreases)/increases were included in ComEd’s, BGE’s,ComEd's, BGE's, Pepco's, DPL's and ACE's 20172018 annual electric transmission formula rate filings:updates.
 2017
Annual Transmission Filings(a)
ComEd BGE Pepco DPL ACE
Initial revenue requirement
    increase
$44
 $31
 $5
 $6
 $20
Annual reconciliation (decrease) increase(33) 3
 15
 8
 22
Dedicated facilities decrease(b)
—
 (8) —
 —
 —
Total revenue requirement increase$11
 $26
 $20
 $14
 $42
          
Allowed return on rate base(c)
8.43% 7.47% 7.92% 7.16% 8.02%
Allowed ROE(d)
11.50% 10.50% 10.50% 10.50% 10.50%
 2018
Annual Transmission Updates(a)(b)
ComEd BGE Pepco DPL ACE
Initial revenue requirement (decrease) increase$(44) $10
 $6
 $14
 $4
Annual reconciliation increase (decrease)18
 4
 2
 13
 (4)
Dedicated facilities increase(c)
—
 12
 —
 —
 —
Total revenue requirement (decrease) increase$(26) $26
 $8
 $27
 $—
          
Allowed return on rate base(d)
8.32% 7.61% 7.82% 7.29% 8.02%
Allowed ROE(e)
11.50% 10.50% 10.50% 10.50% 10.50%
___________________
(a)All rates are effective June 2017,2018, subject to review by the FERC and other parties, which is due by fourth quarter 2017.2018.
(b)The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA.  See further discussion above. 
(c)BGE's transmission revenues include a FERC approvedFERC-approved dedicated facilities charge to recover the costs of providing transmission service to a specifically designated load by BGE.
(c)(d)Represents the weighted average debt and equity return on transmission rate bases.
(d)(e)As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization.
ForSee Note 3 - Regulatory Matters of the Exelon 2017 Form 10-K for additional information regarding transmission formula rate filings see Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K.updates.
Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate wouldwill be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the final outcome of the settlement or hearing proceedings,this proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a revenue decrease of $6 million. The revenue decrease of $6 million included an approximately $20 million reduction as a result of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.
PJM Transmission Rate Design and Operating Agreements (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)(All Registrants). 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 the Utility Registrants, filed a proposed settlement with FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. The settlement included provisions for monthly credits or charges related

88
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Exelon andto the Utility Registrants, filed a proposed Settlement with FERC.  If the Settlement is approved, 50% of the costs of the 500 kV and above facilities approved by the PJM Board on or before Februaryperiods prior to January 1, 2013 will be socialized across PJM and 50% will be allocated according to a formula that calculates the flows on the transmission facilities.  Each state that is a party in this proceeding either signed, or did not oppose, the settlement.  The Settlement is opposed by a number of merchant transmission owners and New York load-serving entities. The Settlement includes provisions for monthly credits or charges2016 that are expected to be mostly refunded or recovered through customerPJM wholesale transmission rates through December 2025.
On May 31, 2018, FERC issued an order approving the settlement and directed PJM to adjust wholesale transmission rates within 30 days. Pursuant to the order, similar charges for the period January 1, 2016 through June 30, 2018 will also be refunded or recovered through PJM wholesale transmission rates over the subsequent 12-month period. PJM commenced billing the refunds and charges associated with this settlement in August 2018. The Utility Registrants expect to refund or recover these settlement amounts through prospective electric distribution customer rates. On July 2, 2018, a 10-year period based on negotiated numbersnumber of parties filed petitions for charges priorrehearing or clarification.
Pursuant 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 toFERC approval by FERC.
DOE Notice of Proposed Rulemaking (Exelon and Generation).  On August 23, 2017, the DOE released its report on the reliability of the electric grid. One aspectsettlement and the expected refund or recovery of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September, 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. The DOE issued the NOPR under an infrequently-used section of the DOE Organization Act under which the FERC has exclusive jurisdiction to consider and take any final action related to NOPRs proposed by the DOE. The DOE NOPR recommended that the FERC take comments for 45 days after publicationassociated amounts from electric distribution customers, in the Federal Registersecond quarter of 2018 and issue a final order 60 days after such publication.  On October 2, 2017,as adjusted in the FERC issued a notice inviting comments regardingthird quarter of 2018, the DOE NOPR within 21 days and established a new docket whereinUtility Registrants recorded the FERC will consider the matter. On October 23, 2017, Exelon filed comments with the FERC, supporting the goals of the NOPR and urging the agency to take swift action to protect customersfollowing payables to/receivables from power supply interruptions and ensure resiliency in a way that appropriately balances the value and cost to customers.  Exelon cannot predict the final outcome of the proceeding or its potential impact, if any, on Exelon or Generation.
Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs (Exelon and Generation). PJM and NYISO capacity markets includerelated regulatory assets/liabilities. Generation recorded a Minimum Offer Price Rule (MOPR) that is intended$41 million net payable 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 reliabilitya pre-tax charge within Purchased power and valuefuel expense in Exelon's and Generation's Consolidated Statements 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)Operations 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. The EPSA parties have filed motions to expedite both proceedings. 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, for Generation's facilities in NYISO and PJM expected to receive ZEC compensation (Quad Cities, Ginna, Nine Mile Point and FitzPatrick), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in those auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any such mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. On August 30, 2017, EPSA filed motions to lodge the district court decisions dismissing the complaints and urging FERC to act expeditiously on its requests to expand the MOPR. On September 14, 2017, Exelon filed a response in each docket noting that it does not oppose the motions to lodge but arguing that the requests to expedite a decision on the requests to expand the MOPR have no merit. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.

Comprehensive Income.
89
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

 PJM Receivable PJM Payable Regulatory Asset Regulatory Liability
Exelon$220
 $176
 $136
 $221
Generation—
 41
 —
 —
ComEd122
 —
 —
 122
PECO85
 —
 —
 85
BGE—
 51
 51
 —
PHI(a)
13
 84
 85
 14
Pepco—
 84
 84
 —
DPL10
 —
 —
 10
ACE3
 —
 1
 4
__________
(a)PHI reflects the consolidated impacts of Pepco, DPL, and ACE.
Operating License Renewals (Exelon and Generation).On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-year license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) with Maryland Department of the Environment (MDE) for Conowingo, Generation continues to work with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. 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 April 21, 2016, ExelonGeneration and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a Settlement Agreement resolving all fish passage issues between the parties. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the 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
On April 27, 2018, the remaining issuesMDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to Conowingo involving various stakeholders mayreduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, effectunfavorable impact on Exelon’s and Generation’s results of operations, cash flows and financial positionpositions through an increase in capital

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

expenditures and operating costs. costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous violating MDE regulations, state, federal, and constitutional law. Generation also requested that FERC defer action on the federal license while these significant state and federal law issues are pending. On July 9, 2018, MDE filed a motion to dismiss Generation's complaint in state court, which was granted without prejudice on October 9, 2018. The court found MDE's Certification was not a "final decision" of Exelon's rights and that because Exelon's motion for reconsideration remains pending, as does its administrative appeal of the 401 Certification, there was no final administrative decision for the court to review at this time. Exelon continues to challenge the 401 Certification through the administrative process and in federal court. Exelon and Generation cannot predict the final outcome or its financial impact, if any, on Exelon or Generation.
As of September 30, 2017, $302018, $35 million of direct costs associated with Conowingo licensing efforts have been capitalized. See Note 3 -— Regulatory Matters of the Exelon 20162017 Form 10-K for additional information on Generation's operating license renewal efforts.
On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3. Generation anticipates the second license renewal process to take approximately 2 years from the application submission until completion of the NRC’s review process. Peach Bottom Units 2 and 3 are licensed to operate through 2033 and 2034, respectively.
Regulatory Assets and Liabilities (Exelon ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)the Utility Registrants)
Exelon ComEd, PECO, BGE, PHI, Pepco, DPL and ACEthe Utility Registrants 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.

90
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 ACEthe Utility Registrants as of September 30, 20172018 and December 31, 2016. For2017. See Note 3 — Regulatory Matters of the Exelon 2017 Form 10-K for additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K.liabilities.
         Successor      
September 30, 2017Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory assets               
Pension and other postretirement benefits(a)
$4,020
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Deferred income taxes(b)
2,423
 347
 1,678
 100
 298
 195
 45
 58
AMI programs660
 159
 40
 219
 242
 163
 79
 —
Under-recovered distribution service costs(c)
256
 256
 —
 —
 —
 —
 —
 —
Energy efficiency costs78
 78
 —
 —
 —
 —
 —
 —
Debt costs120
 38
 1
 12
 75
 16
 8
 5
Fair value of long-term debt773
 —
 —
 —
 632
 —
 —
 —
Fair value of PHI's unamortized energy contracts830
 —
 —
 —
 830
 —
 —
 —
Severance2
 —
 —
 2
 —
 —
 —
 —
Asset retirement obligations108
 73
 22
 13
 —
 —
 —
 —
MGP remediation costs300
 277
 23
 —
 —
 —
 —
 —
Under-recovered uncollectible accounts70
 60
 —
 —
 10
 —
 —
 10
Renewable energy277
 277
 —
 —
 —
 —
 —
 —
Energy and transmission programs (d)(e)(f)(g)(h)(i)
65
 3
 —
 26
 36
 6
 9
 21
Deferred storm costs31
 —
 —
 —
 31
 9
 5
 17
Electric generation-related regulatory asset3
 —
 —
 3
 —
 —
 —
 —
Energy efficiency and demand response programs599
 —
 1
 284
 314
 233
 81
 —
Merger integration costs(j)(k)(l)(m)
47
 —
 —
 7
 40
 20
 11
 9
Under-recovered revenue decoupling(n)
72
 —
 —
 34
 38
 33
 5
 —
COPCO acquisition adjustment6
 —
 —
 —
 6
 —
 6
 —
Workers compensation and long-term disability cost33
 —
 —
 —
 33
 33
 —
 —
Vacation accrual38
 —
 14
 —
 24
 —
 14
 10
Securitized stranded costs93
 —
 —
 —
 93
 —
 —
 93
CAP arrearage9
 —
 9
 —
 —
 —
 —
 —
Removal costs
518
 —
 —
 —
 518
 144
 98
 277
Other71
 6
 21
 5
 40
 28
 8
 4
Total regulatory assets11,502
 1,574
 1,809
 705
 3,260
 880
 369
 504
Less: current portion1,264
 187
 36
 208
 568
 181
 69
 87
Total noncurrent regulatory assets$10,238
 $1,387
 $1,773
 $497
 $2,692
 $699
 $300
 $417
         Successor      
September 30, 2017Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory liabilities               
Other postretirement benefits$41
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Nuclear decommissioning2,971
 2,438
 533
 —
 —
 —
 —
 —
Removal costs1,588
 1,337
 —
 119
 132
 22
 110
 —
Deferred rent37
 —
 —
 —
 37
 —
 —
 —
Energy efficiency and demand response programs62
 33
 29
 —
 —
 —
 —
 —
DLC program costs8
 —
 8
 —
 —
 —
 —
 —
Electric distribution tax repairs50
 —
 50
 —
 —
 —
 —
 —
Gas distribution tax repairs14
 —
 14
 —
 —
 —
 —
 —
Energy and transmission programs (d)(e)(f)(g)(h)(i)
139
 54
 68
 —
 17
 3
 9
 5
Renewable portfolio standards costs46
 46
 —
 —
 —
 —
 —
 —
Zero emission credit costs71
 71
 —
 —
 —
 —
 —
 —
Other75
 5
 17
 28
 25
 1
 9
 13
Total regulatory liabilities5,102
 3,984
 719
 147
 211
 26
 128
 18
Less: current portion553
 249
 159
 63
 65
 5
 42
 18
Total noncurrent regulatory liabilities$4,549
 $3,735
 $560
 $84
 $146
 $21
 $86
 $—

September 30, 2018Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory assets               
Pension and other postretirement benefits(a)
$3,710
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Deferred income taxes391
 —
 381
 —
 10
 10
 —
 —
AMI programs(c)
583
 142
 27
 198
 216
 144
 72
 —
Electric distribution formula rate(d)
228
 228
 —
 —
 —
 —
 —
 —
Energy efficiency costs357
 357
 —
 —
 —
 —
 —
 —
Debt costs102
 34
 1
 11
 68
 15
 7
 6
Fair value of long-term debt716
 —
 —
 —
 581
 —
 —
 —
Fair value of PHI's unamortized energy contracts600
 —
 —
 —
 600
 —
 —
 —
Asset retirement obligations114
 76
 22
 15
 1
 1
 —
 —
MGP remediation costs318
 299
 19
 —
 —
 —
 —
 —
Under-recovered uncollectible accounts71
 71
 —
 —
 —
 —
 —
 —
Renewable energy260
 259
 —
 —
 1
 —
 —
 1
Energy and transmission programs(e)(f)(g)(h)(i)(j)
251
 7
 50
 72
 122
 93
 15
 14
Deferred storm costs45
 —
 —
 —
 45
 11
 5
 29
Energy efficiency and demand response programs561
 —
 2
 291
 268
 194
 74
 —
Merger integration costs(k)(l)(m)
44
 —
 —
 4
 40
 18
 12
 10
Under-recovered revenue decoupling(n)
64
 —
 —
 —
 64
 64
 —
 —
COPCO acquisition adjustment3
 —
 —
 —
 3
 —
 3
 —
Workers compensation and long-term disability costs36
 —
 —
 —
 36
 36
 —
 —
Vacation accrual24
 —
 11
 —
 13
 —
 8
 5
Securitized stranded costs57
 —
 —
 —
 57
 —
 —
 57
CAP arrearage10
 —
 10
 —
 —
 —
 —
 —
Removal costs555
 —
 —
 —
 555
 156
 97
 302
DC PLUG charge168
 —
 —
 —
 168
 168
 —
 —
Other74
 12
 9
 6
 47
 36
 8
 3
Total regulatory assets9,342
 1,485
 532
 597
 2,895
 946
 301
 427
Less: current portion1,340
 256
 84
 195
 521
 284
 66
 44
Total noncurrent regulatory assets$8,002
 $1,229
 $448
 $402
 $2,374
 $662
 $235
 $383
91
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

         Successor      
December 31, 2016Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory assets               
Pension and other postretirement benefits (a)
$4,162
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Deferred income taxes (b)
2,016
 75
 1,583
 98
 260
 171
 38
 51
AMI programs701
 164
 49
 230
 258
 174
 84
 —
Under-recovered distribution service costs (c)
188
 188
 —
 —
 —
 —
 —
 —
Debt costs124
 42
 1
 7
 81
 17
 9
 6
Fair value of long-term debt812
 —
 —
 —
 671
 —
 —
 —
Fair value of PHI's unamortized energy contracts1,085
 —
 —
 —
 1,085
 —
 —
 —
Severance5
 —
 —
 5
 —
 —
 —
 —
Asset retirement obligations111
 76
 23
 12
 —
 —
 —
 —
MGP remediation costs305
 278
 26
 1
 —
 —
 —
 —
Under-recovered uncollectible accounts56
 56
 —
 —
 —
 —
 —
 —
Renewable energy260
 258
 —
 —
 2
 —
 —
 2
Energy and transmission programs (d)(e)(f)(g)(h)(i)
89
 23
 —
 38
 28
 6
 5
 17
Deferred storm costs36
 —
 —
 1
 35
 12
 5
 18
Electric generation-related regulatory asset10
 —
 —
 10
 —
 —
 —
 —
Rate stabilization deferral7
 —
 —
 7
 —
 —
 —
 —
Energy efficiency and demand response programs621
 —
 1
 285
 335
 250
 85
 —
Merger integration costs(j)(k)(l)(m)
25
 —
 —
 10
 15
 11
 4
 —
Under-recovered revenue decoupling(n)
27
 —
 —
 3
 24
 21
 3
 —
COPCO acquisition adjustment8
 —
 —
 —
 8
 —
 8
 —
Workers compensation and long-term disability costs34
 —
 —
 —
 34
 34
 —
 —
Vacation accrual31
 —
 7
 —
 24
 —
 14
 10
Securitized stranded costs138
 —
 —
 —
 138
 —
 —
 138
CAP arrearage11
 —
 11
 —
 —
 —
 —
 —
Removal costs477
 —
 —
 —
 477
 134
 88
 255
Other49
 7
 9
 5
 29
 22
 5
 4
Total regulatory assets11,388
 1,167
 1,710
 712
 3,504
 852
 348
 501
Less: current portion1,342
 190
 29
 208
 653
 162
 59
 96
Total noncurrent regulatory assets$10,046
 $977
 $1,681
 $504
 $2,851
 $690
 $289
 $405
         Successor      
December 31, 2016Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory liabilities               
Other postretirement benefits$47
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Nuclear decommissioning2,607
 2,169
 438
 —
 —
 —
 —
 —
Removal costs1,601
 1,324
 —
 141
 136
 18
 118
 —
Deferred rent39
 —
 —
 —
 39
 —
 —
 —
Energy efficiency and demand response programs185
 141
 41
 —
 3
 3
 —
 —
DLC program costs8
 —
 8
 —
 —
 —
 —
 —
Electric distribution tax repairs76
 —
 76
 —
 —
 —
 —
 —
Gas distribution tax repairs20
 —
 20
 —
 —
 —
 —
 —
Energy and transmission programs (d)(e)(f)(g)(h)(i)
134
 60
 56
 —
 18
 8
 5
 5
Other72
 4
 5
 19
 41
 2
 17
 20
Total regulatory liabilities4,789
 3,698
 644
 160
 237
 31
 140
 25
Less: current portion602
 329
 127
 50
 79
 11
 43
 25
Total noncurrent regulatory liabilities$4,187
 $3,369
 $517
 $110
 $158
 $20
 $97
 $—
_________
September 30, 2018Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory liabilities               
Other postretirement benefits$20
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Deferred income taxes(b)
5,054
 2,418
 —
 1,015
 1,621
 734
 493
 394
Nuclear decommissioning2,958
 2,469
 489
 —
 —
 —
 —
 —
Removal costs1,566
 1,370
 —
 67
 129
 20
 109
 —
Deferred rent34
 —
 —
 —
 34
 —
 —
 —
Energy efficiency and demand response programs10
 3
 5
 —
 2
 —
 —
 2
DLC program costs7
 —
 7
 —
 —
 —
 —
 —
Electric distribution tax repairs10
 —
 10
 —
 —
 —
 —
 —
Gas distribution tax repairs4
 —
 4
 —
 —
 —
 —
 —
Energy and transmission programs(e)(f)(g)(h)(i)(j)
372
 204
 143
 7
 18
 —
 14
 4
Over-recovered revenue decoupling(n)
21
 —
 —
 17
 4
 —
 4
 —
Renewable portfolio standards costs140
 140
 —
 —
 —
 —
 —
 —
Zero emission credit costs18
 18
 —
 —
 —
 —
 —
 —
Over-recovered uncollectible accounts2
 —
 —
 —
 2
 —
 —
 2
Merger integration costs(l)
3
 —
 —
 —
 3
 —
 3
 —
TCJA income tax benefit over-recoveries(o)
108
 —
 61
 19
 28
 6
 8
 14
Other118
 16
 21
 40
 41
 4
 23
 12
Total regulatory liabilities10,445
 6,638
 740
 1,165
 1,882
 764
 654
 428
Less: current portion689
 320
 159
 95
 99
 5
 67
 27
Total noncurrent regulatory liabilities$9,756
 $6,318
 $581
 $1,070
 $1,783
 $759
 $587
 $401
(a)As of September 30, 2017 and December 31, 2016, the pension and other postretirement benefits regulatory asset at Exelon includes regulatory assets of $969 million and $995 million, respectively, as a result of the PHI Merger related to unrecognized costs that are probable of regulatory recovery. The regulatory assets are amortized 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.
(b)As of September 30, 2017, includes transmission-related income tax regulatory assets that require FERC approval separate from the transmission formula rate of $73 million, $42 million, $34 million, $23 million and $21 million for ComEd, BGE, Pepco, DPL and ACE, respectively. 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. On December 13, 2016, BGE filed with FERC to begin recovering these existing and any similar future regulatory assets through its transmission formula rate. On May 9, 2017, FERC accepted BGE’s filing

92
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

and made effective BGE’s proposed modifications to its transmission formula rate, subject to refund and further Commission order. ComEd, Pepco, DPL, and ACE are expected to make similar filings with FERC and other parties
December 31, 2017Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory assets               
Pension and other postretirement benefits(a)
$3,848
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Deferred income taxes306
 —
 297
 —
 9
 9
 —
 —
AMI programs(c)
640
 155
 36
 214
 235
 158
 77
 —
Electric distribution formula rate(d)
244
 244
 —
 —
 —
 —
 —
 —
Energy efficiency costs166
 166
 —
 —
 —
 —
 —
 —
Debt costs116
 37
 1
 11
 73
 15
 8
 5
Fair value of long-term debt758
 —
 —
 —
 619
 —
 —
 —
Fair value of PHI's unamortized energy contracts750
 —
 —
 —
 750
 —
 —
 —
Asset retirement obligations109
 73
 22
 14
 —
 —
 —
 —
MGP remediation costs295
 273
 22
 —
 —
 —
 —
 —
Under-recovered uncollectible accounts61
 61
 —
 —
 —
 —
 —
 —
Renewable energy258
 256
 —
 —
 2
 —
 1
 1
Energy and transmission programs(e)(g)(h)(i)(j)
82
 6
 1
 23
 52
 11
 15
 26
Deferred storm costs27
 —
 —
 —
 27
 7
 5
 15
Energy efficiency and demand response programs596
 —
 1
 285
 310
 229
 81
 —
Merger integration costs(k)(l)(m)
45
 —
 —
 6
 39
 20
 10
 9
Under-recovered revenue decoupling(n)
55
 —
 —
 14
 41
 38
 3
 —
COPCO acquisition adjustment5
 —
 —
 —
 5
 —
 5
 —
Workers compensation and long-term disability costs35
 —
 —
 —
 35
 35
 —
 —
Vacation accrual19
 —
 6
 —
 13
 —
 8
 5
Securitized stranded costs79
 —
 —
 —
 79
 —
 —
 79
CAP arrearage8
 —
 8
 —
 —
 —
 —
 —
Removal costs529
 —
 —
 —
 529
 150
 93
 286
DC PLUG charge190
 —
 —
 —
 190
 190
 —
 —
Other67
 8
 16
 4
 39
 29
 8
 4
Total regulatory assets9,288
 1,279
 410
 571
 3,047
 891
 314
 430
Less: current portion1,267
 225
 29
 174
 554
 213
 69
 71
Total noncurrent regulatory assets$8,021
 $1,054
 $381
 $397
 $2,493
 $678
 $245
 $359
December 31, 2017Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory liabilities               
Other postretirement benefits$30
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Deferred income taxes(b)
5,241
 2,479
 —
 1,032
 1,730
 809
 510
 411
Nuclear decommissioning3,064
 2,528
 536
 —
 —
 —
 —
 —
Removal costs1,573
 1,338
 —
 105
 130
 20
 110
 —
Deferred rent36
 —
 —
 —
 36
 —
 —
 —
Energy efficiency and demand response programs23
 4
 19
 —
 —
 —
 —
 —
DLC program costs7
 —
 7
 —
 —
 —
 —
 —
Electric distribution tax repairs35
 —
 35
 —
 —
 —
 —
 —
Gas distribution tax repairs9
 —
 9
 —
 —
 —
 —
 —
Energy and transmission programs(e)(f)(i)(j)
111
 47
 60
 —
 4
 —
 1
 3
Renewable portfolio standard costs63
 63
 —
 —
 —
 —
 —
 —
Zero emission credit costs112
 112
 —
 —
 —
 —
 —
 —
Over-recovered uncollectible accounts2
 —
 —
 —
 2
 —
 —
 2
Other82
 6
 24
 26
 26
 3
 14
 6
Total regulatory liabilities10,388
 6,577
 690
 1,163
 1,928
 832
 635
 422
Less: current portion523
 249
 141
 62
 56
 3
 42
 11
Total noncurrent regulatory liabilities$9,865
 $6,328
 $549
 $1,101
 $1,872
 $829
 $593
 $411

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

__________
(a)Includes regulatory assets established at the Constellation and PHI merger dates of $401 million and $897 million, respectively, as of September 30, 2018 and $440 million and $953 million, respectively, as of December 31, 2017 related to the rate regulated portions of the deferred costs associated with legacy Constellation’s and PHI’s pension and other postretirement benefit plans that are being amortized and recovered over approximately 12 years and 3 to 15 years, respectively (as established at the respective acquisition dates). The Utility Registrants are not earning or paying a return on these amounts.
(b)As of September 30, 2018, includes transmission-related income tax regulatory liabilities that require FERC approval separate from the transmission formula rate of $464 million, $135 million, $136 million, $145 million and $141 million for ComEd, BGE, Pepco, DPL and ACE, respectively. As of December 31, 2017, includes transmission-related income tax regulatory liabilities that require FERC approval separate from the transmission formula rate of $484 million, $137 million, $147 million, $148 million and $147 million for ComEd, BGE, Pepco, DPL and ACE, respectively.
(c)As of September 30, 2017, ComEd’s2018, BGE's regulatory asset of $256$198 million was comprisedincludes $117 million of $200unamortized incremental deployment costs under the program, $48 million forof unamortized costs of the 2015 - 2017 annual reconciliationsnon-AMI meters replaced under the AMI program, and $56$33 million related to significant one-time events including $11 million of deferred stormpost-test year incremental program deployment costs $7 million of Constellation and PHI merger and integration related costs, $6 million of emerald ash borer costs, and $32 million of smart meter related costs.incurred prior to approval became effective June 2016. As of December 31, 2016, ComEd’s2017, BGE's regulatory asset of $188$214 million was comprisedincludes $129 million of $134unamortized incremental deployment costs under the program, $53 million forof unamortized costs of the 2015non-AMI meters replaced under the AMI program, and 2016 annual reconciliations and $54$32 million related to significant one-time events, including $20 million of deferred stormpost-test year incremental program deployment costs and $11 million of Constellation and PHI merger and integration related costs, and $23 million of smart meter related costs. See Note 4— Mergers, Acquisitions and Dispositionsincurred prior to approval became effective June 2016. Recovery of the Exelon 2016 Form 10-K for further information.post-test year incremental deployment costs will be addressed in a future base rate proceeding.
(d)As of September 30, 2018, ComEd’s regulatory asset of $228 million was comprised of $165 million for the 2016, 2017 and 2018 annual reconciliations and $63 million related to significant one-time events. As of December 31, 2017, ComEd’s regulatory asset of $244 million was comprised of $186 million for the 2016 and 2017 annual reconciliations and $58 million related to significant one-time events.
(e)As of September 30, 2018, ComEd’s regulatory asset of $7 million represents transmission costs recoverable through its FERC approved formula rate. As of September 30, 2018, ComEd’s regulatory liability of $54$204 million included $22$101 million related to the PJM Transmission Rate Design Settlement, $72 million related to over-recovered energy costs and $32$31 million associated with revenues received for renewable energy requirements. As of December 31, 2016,2017, ComEd’s regulatory asset of $23$6 million included $15 million associated withrepresents transmission costs recoverable through its FERC approved formula rate and $8 million of Constellation merger and integration costs to be recovered upon FERC approval.rate. As of December 31, 2016,2017, ComEd’s regulatory liability of $60$47 million included $30$14 million related to over-recovered energy costs and $30$33 million associated with revenues received for renewable energy requirements.
(e)(f)As of September 30, 2018, PECO’s regulatory asset of $50 million represents the under-recovered natural gas costs under the PGC. As of December 31, 2017, PECO’s regulatory asset of $1 million is related to under-recovered costs under the TSC program. As of September 30, 2018, PECO's regulatory liability of $68$143 million included $34$85 million related to the PJM Transmission Rate Design Settlement, $43 million related to over-recovered costs under the DSP program, $21$3 million related to the over-recovered natural gas costs under the PGCtransmission service charges and $13$12 million related to over-recovered non-bypassable transmission service charges. As of December 31, 2016,2017, PECO's regulatory liability of $56$60 million included $34$36 million related to over-recovered costs under the DSP program, $10$12 million related to over-recovered non-bypassable transmission service charges $8and $12 million related to the over-recovered natural gas costs under the PGC and $4 million related to the over-recovered electric transmission costs.PGC.
(f)(g)As of September 30, 2017,2018, BGE's regulatory asset of $26$72 million included $5$48 million related to under-recovered electric energy costs,the PJM Transmission Rate Design Settlement, $14 million related to under-recovered natural gas costs, $3 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $7 million related to under-recovered electric energy costs and $4$3 million of abandonment costs to be recovered upon FERC approval. As of September 30, 2018, BGE's regulatory liability of $7 million related to over-recovered natural gas costs. As of December 31, 2016,2017, BGE’s regulatory asset of $38$23 million included $4$7 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $28$5 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval and $3$8 million of under-recovered natural gas costs.
(g)(h)As of September 30, 2018, Pepco's regulatory asset of $93 million included $74 million related to the PJM Transmission Rate Design Settlement, $7 million of transmission costs recoverable through its FERC approved formula rate and $12 million related to under-recovered electric energy costs. As of December 31, 2017, Pepco's regulatory asset of $6$11 million included $3 million of transmission costs recoverable through its FERC approved formula rate and $3$8 million of under-recovered electric energy costs. As of September 30, 2017, Pepco's regulatory liability of $3 million related to over-recovered electric energy costs. 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.
(h)(i)As of September 30, 2017,2018, DPL's regulatory asset of $9$15 million included $4$14 million of transmission costs recoverable through its FERC approved formula rate and $5$1 million related to under-recovered electric energy costs. As of September 30, 2017,2018, DPL's regulatory liability of $9$14 million included $10 million related to the PJM Transmission Rate Design Settlement and $4 million related to over-recovered electric energy and gas fuel costs. As of December 31, 2016,2017, DPL's regulatory asset of $5$15 million included $1$8 million of transmission costs recoverable through its FERC approved formula rate and $4$7 million related to under-recovered electric energy costs. As of December 31, 2017, DPL's regulatory liability of $1 million related to over-recovered electric energy costs.
(j)As of September 30, 2018, ACE's regulatory asset of $14 million included $7 million of transmission costs recoverable through its FERC approved formula rate and $7 million of under-recovered electric energy costs. As of December 31, 2016, DPL'sSeptember 30, 2018, ACE's regulatory liability of $5$4 million included $2$3 million ofrelated to the PJM Transmission Rate Design Settlement and $1 million related to over-recovered electric energy costs and $3 million of over-recovered transmission costs.
(i)As of September 30,December 31, 2017, ACE's regulatory asset of $21$26 million included $11 million of transmission costs recoverable through its FERC approved formula rate and $10 million of under-recovered electric energy costs. As of September 30, 2017, ACE's regulatory liability of $5 million related to over-recovered electric energy 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$15 million of under-recovered electric energy costs. As of December 31, 2016,2017, ACE's regulatory liability of $5$3 million included $4 million of over-recovered transmission costs and $1 million ofrelated to over-recovered electric energy costs.
(j)As of September 30, 2017 and December 31, 2016, BGE's regulatory asset of $7 million and $10 million, respectively, included $5 million and $6 million, respectively, of previously incurred PHI acquisition costs as authorized by the June 2016 rate case order.
(k)As of September 30, 2017,2018, Pepco’s regulatory asset of $20$18 million represents previously incurred PHI acquisitionintegration costs, including $11$9 million authorized for recovery in Maryland and $9 million expected to be recovered in the District of Columbia service territory. As of December 31, 2016, Pepco's2017, Pepco’s regulatory asset of $11$20 million represents previously incurred PHI acquisitionintegration costs, including $11 million authorized for recovery in Maryland. Maryland and $9 million expected to be recovered in the District of Columbia service territory.

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

(l)As of September 30, 2018, DPL’s regulatory asset of $12 million represents previously incurred PHI integration costs, including $4 million authorized for recovery in Maryland, $5 million authorized for recovery in Delaware electric rates, $2 million authorized for recovery in Delaware gas rates and $1 million expected to be recovered in electric rates in the Delaware and Maryland service territories. As of September 30, 2018, DPL’s regulatory liability of $3 million represents net synergy savings incurred related to PHI integration costs that are expected to be returned in electric and gas rates in the Delaware service territory. As of December 31, 2017, DPL’s regulatory asset of $11$10 million represents previously incurred PHI acquisitionintegration costs, including $4 million authorized for recovery in Maryland, $5 million authorized for recovery in Delaware electric rates, and $2$1 million expected to be recovered in electric and gas rates in the Maryland and Delaware service territory. As of December 31, 2016, DPL's regulatory asset of $4 million represents previously incurred PHI acquisition costs expected to be recovered in the Maryland service territory.territories.
(m)As of September 30, 2018 and December 31, 2017, ACE’s regulatory asset of $10 million and $9 million, respectively, represents previously incurred PHI acquisitionintegration costs expected to be recovered in the New Jersey service territory.
(n)Represents the electric and natural gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of September 30, 2017,2018, BGE had a regulatory asset of $24less than $1 million related to under-recovered electric revenue decoupling and a regulatory liability of $17 million related to over-recovered natural gas revenue decoupling. As of December 31, 2017, BGE had a regulatory asset of $10 million related to under-recovered electric revenue decoupling and $4 million related to under-recovered natural gas revenue decoupling. As of December 31, 2016, BGE had a regulatory asset of $2 million
(o)Represents over-recoveries related to under-recovered natural gas revenue decouplingthe change in the federal income tax rate with the enactment of the TCJA. These regulatory liabilities will be amortized as the TCJA income tax benefits are passed back to customers. See Tax Cuts and $1 million related to under-recovered electric revenue decoupling.Jobs Act disclosures above for additional information on the regulatory proceedings.
Capitalized Ratemaking Amounts Not Recognized (Exelon ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)the Utility Registrants)
The following table illustrates ourpresents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes on ourExelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in ourthe related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.
 Exelon 
ComEd(a)
 PECO 
BGE(b)
 PHI 
Pepco(c)
 
DPL(c)
 ACE
September 30, 2017$71
 $7
 $—
 $54
 $10
 $6
 $4
 $—
                
 Exelon 
ComEd(a)
 PECO 
BGE(b)
 PHI 
Pepco(c)
 
DPL(c)
 ACE
December 31, 2016$72
 $5
 $—
 $57
 $10
 $6
 $4
 $—
 Exelon 
ComEd(a)
 PECO 
BGE(b)
 PHI 
Pepco(c)
 
DPL(c)
 ACE
September 30, 2018$67
 $8
 $—
 $50
 $9
 $5
 $4
 $—
                
 Exelon 
ComEd(a)
 PECO 
BGE(b)
 PHI 
Pepco(c)
 
DPL(c)
 ACE
December 31, 2017$69
 $6
 $—
 $53
 $10
 $6
 $4
 $—
_________
(a)Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its under-recoveredelectric distribution services costsformula rate regulatory assets.
(b)BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI Programs.programs.
(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.

93
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Purchase of Receivables Programs (Exelon ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)the Utility Registrants)
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 to recover primarily uncollectible accounts expense from the suppliers. PECO is required to purchase receivables 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 ACEthe Utility Registrants 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'sthe Utility Registrant's Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of September 30, 20172018 and December 31, 2016.2017.
        Successor      
As of September 30, 2017Exelon ComEd PECO BGE PHI Pepco DPL ACE
As of September 30, 2018Exelon ComEd PECO BGE PHI Pepco DPL ACE
Purchased receivables$312
 $89
 $68
 $55
 $100
 $66
 $10
 $24
$379
 $120
 $91
 $60
 $108
 $69
 $11
 $28
Allowance for uncollectible accounts(a)
(33) (13) (5) (4) (11) (6) (1) (4)(37) (19) (5) (3) (10) (5) (1) (4)
Purchased receivables, net$279
 $76
 $63
 $51
 $89
 $60
 $9
 $20
$342
 $101
 $86
 $57
 $98
 $64
 $10
 $24
         Successor      
As of December 31, 2016Exelon ComEd PECO BGE PHI Pepco DPL ACE
Purchased receivables$313
 $87
 $72
 $59
 $95
 $63
 $10
 $22
Allowance for uncollectible accounts(a)
(37) (14) (6) (4) (13) (7) (2) (4)
Purchased receivables, net$276
 $73
 $66
 $55
 $82
 $56
 $8
 $18
As of December 31, 2017Exelon ComEd PECO BGE PHI Pepco DPL ACE
Purchased receivables$298
 $87
 $70
 $58
 $83
 $56
 $9
 $18
Allowance for uncollectible accounts(a)
(31) (14) (5) (3) (9) (5) (1) (3)
Purchased receivables, net$267
 $73
 $65
 $55
 $74
 $51
 $8
 $15
_________
(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.

6.7. Impairment of Long-Lived Assets (Exelon and Generation)
Long-Lived Assets (Exelon and Generation)
Generation evaluatesRegistrants evaluate long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. EGTP’s operating cash flows have been negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate an orderly sales process to sell the assets of its wholly owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP. As a result, as of June 30, 2017, and September 30, 2017, certain of EGTP’s assets and liabilities were classified as held for sale at their respective fair values less costs to sell and included in the other current assets and other current liabilities balances on Exelon’s and Generation’s Consolidated Balance Sheets. As of June 30, 2017, the fair value analysis was based on an 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 this analysis, in the second quarter 2017, Exelon and Generation recorded a pre-tax impairment charge of $418 million within Operating and maintenance expense on their Consolidated Statements of Operations and Comprehensive Income. In the third quarter 2017, Exelon and Generation recorded an additional pre-tax impairment charge of $40 million within Operating and maintenance expense on their Consolidated Statements of Operations and Comprehensive Income to reflect an indicated decline in fair value based on new information obtained in the quarter through the orderly sales process. See Note 4 - Mergers, Acquisitions and Dispositions and Note 11 - Debt and Credit Agreements, for further information.
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

94
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

14 - Debt and Credit Agreements of the Exelon 2016 Form 10-K) 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 business by executing a forbearance agreement with the lenders of the nonrecourse debt. 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 of the Exelon 2016 Form 10-K for further information.
In the second quarter of 2016,2018, updates to the Company'sExelon'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 theirits 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 net carrying amount of approximately $60$41 million were written down to their fair value of $24 millionfully impaired and a pre-tax impairment charge of $36$41 million was recorded during the second quarter inof 2018 within Operating and maintenance expense in Exelon’sExelon's and Generation’sGeneration's Consolidated Statements of Operations and Comprehensive Income.
AlsoDuring the first quarter of 2018, Mystic Unit 9 did not clear in the second quarterISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation announced it had formally notified ISO-NE of 2016, updates to the Company's long-term view, as described above, in conjunction withearly retirement of its Mystic Generating Station's Units 7, 8, 9 and the previous decision to early retire the Clinton and Quad Cities nuclear facilities in IllinoisMystic Jet Unit (Mystic Generating Station assets) absent regulatory reforms. These events suggested that the carrying value of our Midwestits New England asset group may be impaired. As a result, Generation completed a comprehensive

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

review of the estimated undiscounted future cash flows of the MidwestNew England asset group and no impairment charge was required. Further developments such as the failure of ISO-NE to adopt interim and long-term solutions for reliability and fuel security could potentially result in future impairments of the New England asset group, which could be material. See Note 8 — Early Plant Retirements for additional information on the early retirement of the Mystic Generating Station assets.
Like-Kind Exchange Transaction (Exelon)
In June 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII),On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate an orderly sales process to sell the assets of its wholly owned 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).
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.subsidiaries. As a result, Exelon and Generation classified certain of the lease termination, UII received an early termination payment of $360 million from MEAGEGTP's assets and wrote-off the $356 million net investment in the MEAG Headleasesliabilities as held for sale at their respective fair values less costs to sell and the Leases. The transaction resulted inrecorded a pre-tax gainimpairment charge of $4$460 million which is reflected inwithin Operating and maintenance expense in Exelon'son their Consolidated Statements of Operations and Comprehensive Income.Income of which $418 million was recorded in the second quarter of 2017. On November 7, 2017, EGTP and its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware and, as a result, Exelon and Generation deconsolidated EGTP's assets and liabilities from their consolidated financial statements. See Note 12—Income Taxes4 — Mergers, Acquisitions and Dispositions for additional information.
7.8. 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 benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any nuclear plant, and the resulting financial statement impacts, may be affected by a number ofmany 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 for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, and just prior to its next scheduled nuclear refueling outage.
In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York and Three Mile Island (TMI) nuclear plantsplant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. PSEG has also recently made public similar financial challenges facing its New Jersey nuclear plants including Salem,

95
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

of which Generation owns a 42.59% ownership interest. As previously disclosed, Exelon and Generation have committed to cease operation of the Oyster Creek nuclear plant by the end of 2019.
The TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year and will not receive capacity revenue for that period, the third consecutive year that TMI failed to clear the PJM base residual capacity auction. The plant is currently committed to operate through May 2019.
Based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019. The current NRC license for TMI expires in 2034. Generation is proceeding with the market and regulatory notifications that must be made to shut down the plant, including filing of a deactivation notice with PJM on May 30, 2017 and notification to the NRC on June 20, 2017. PJM has subsequently notified Generation that it has not identified any reliability issues and has approved the deactivation of TMI as proposed.
In 2017, as a result of the plant retirement decision of TMI, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $76 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, there will be ongoing annual incremental non-cash charges to earnings stemming from shortening the expected economic useful life of TMI primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions. During the three and nine months ended September 30, 2017, both Exelon’s and Generation’s results include an incremental $112 million and $149 million, respectively, of pre-tax expense for these items. Please refer to Note 13 — Nuclear Decommissioning for additional detail on changes to the nuclear decommissioning ARO balances resulting from the early retirement of TMI.
Income statement expense (pre-tax)Q3 2017 YTD 2017
Depreciation and amortization   
Accelerated depreciation(a)
$106
 $141
Accelerated nuclear fuel amortization6
 8
Total$112
 $149
_________
(a)Reflects incremental accelerated depreciation of plant assets, including any ARC.
Based on insufficient capacity auction results and the lack of progress on Illinois energy legislation, on June 2, 2016, Generation announced a decision to shut down the Clinton and Quad Cities nuclear plants on June 1, 2017 and June 1, 2018, respectively. With the passage of the Illinois ZES on December 7, 2016, and subject to prevailing over any related administrative or legal challenges, Generation reversed this decision and revised the expected economic useful lives for both facilities; 2027 for Clinton and 2032 for Quad Cities. Refer to Note 5 - Regulatory Matters for additional discussion on the Illinois ZES.
Exelon's and Generation's 2016 results included a net incremental $714 million of total 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) Q2 2016 Q3 2016 Q4 2016 YTD 2016
Depreciation and amortization        
Accelerated depreciation(a)
 $115
 $344
 $253
 $712
Accelerated Nuclear Fuel amortization 9
 28
 23
 60
Operating and maintenance        
One time charges(b)
 141
 5
 (120) 26
ARO accretion, net of contractual offset(c)
 —
 2
 —
 2
Contractual offset for ARC depreciation(c)
 (14) (41) (31) (86)
Total $251
 $338
 $125
 $714

96
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

_________
(a)Reflects incremental accelerated depreciation of plant assets, including any ARC, for the period June 2, 2016, through December 6, 2016.
(b)Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.
(c)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, Nine Mile Point, and Generation’s recently acquired FitzPatrick nuclear plant also faced 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, 2046 for Nine Mile Point Unit 2, and 2034 for FitzPatrick). On August 1, 2016, the NYPSC issued an order adopting the New York CES that, subject to prevailing over any administrative or legal challenges, would allow Ginna, Nine Mile Point, and FitzPatrick to continue to operate at least through the life of the program (March 31, 2029). The assumed useful life for depreciation purposes for each facility is through the end of their current operating licenses. Ginna most recently operated under an RSSA which expired March 31, 2017 and has filed the required notice with the NYPSC of its intent to continue operating beyond the expiry of the RSSA. Refer to Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation’s acquisition of FitzPatrick and Note 5 - Regulatory Matters for additional discussion on the Ginna RSSA and the New York CES.
Assuming the successful implementationcontinued effectiveness 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 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 nuclear plants (and now including the newly acquired FitzPatrick) 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.
8. Intangible Assets (Exelonpositions. See Note 6 — Regulatory Matters for additional information on the Illinois ZES and PHI)New York CES.
In Pennsylvania, the TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third quarterconsecutive year that TMI failed to clear the PJM base residual capacity auction. The plant is currently committed to operate through May 2019 and is licensed to operate through 2034. On May 30, 2017, based on these capacity auction results, prolonged periods of 2015, PHI entered intolow wholesale power prices, and the absence of federal or state policies that place a sponsorshipvalue on nuclear energy for its ability to produce electricity without air pollution, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019. Generation has filed the required market and regulatory notifications to shut down the plant. PJM has subsequently notified

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

Generation that it has not identified any reliability issues and has approved the deactivation of TMI as proposed.
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek nuclear plant at the end of its current operating cycle in 2018. On September 17, 2018, Oyster Creek permanently ceased generation operations. In 2010, Generation announced that Oyster Creek would retire by the end of 2019 as part of an agreement with the DistrictState of Columbia for future sponsorship rightsNew Jersey to avoid significant costs associated with the construction of cooling towers to meet the State’s then new environmental regulations. Since then, like other nuclear sites, Oyster Creek has continued to face rising operating costs amid a historically low wholesale power price environment. The decision to retire Oyster Creek in 2018 at the end of its current operating cycle involved consideration of several factors, including economic and operating efficiencies, and avoids a refueling outage scheduled for the fall of 2018 that would have required advanced purchasing of fuel fabrication and materials beginning in late February 2018. Generation has filed the required market and regulatory notifications to shut down the plant. PJM has subsequently notified Generation that it has not identified any reliability issues and has approved the deactivation of Oyster Creek as proposed.
As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized one-time charges in Operating and maintenance expense related to materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments, among other items. In addition to these one-time charges, annual incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions were also recorded. See Note 13 — Asset Retirement Obligations for additional information on changes to the nuclear decommissioning ARO balance.
During the three and nine months ended September 30, 2018, both Exelon's and Generation's results include a net incremental $174 million and $525 million, respectively, of total pre-tax expense associated with the early retirement decisions for TMI and Oyster Creek, as summarized in the table below.
Income statement expense (pre-tax) Q3 2018 YTD 2018
Depreciation and amortization(a)
    
Accelerated depreciation(b)
 $152
 $441
Accelerated nuclear fuel amortization 18
 52
Operating and maintenance(c)
 4
 32
Total $174
 $525
_________
(a)Reflects incremental accelerated depreciation and amortization for TMI and Oyster Creek for the three and nine months ended September 30, 2018. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018.
(b)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c)Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments. It does not include remeasurement of the Oyster Creek ARO. Refer to Note 13 - Asset Retirement Obligations for additional detail.

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

Exelon's and Generation's 2017 results included a net incremental $339 million of total pre-tax expense associated with the early retirement decision for TMI, as summarized in the table below.
Income statement expense (pre-tax) Q2 2017 Q3 2017 Q4 2017 YTD 2017
Depreciation and amortization(a)
        
Accelerated depreciation(b)
 $35
 $106
 $109
 $250
Accelerated nuclear fuel amortization 2
 6
 4
 12
Operating and maintenance(c)
 71
 5
 1
 77
Total $108
 $117
 $114
 $339
_________
(a)Reflects incremental charges for TMI including incremental accelerated depreciation and amortization from May 30, 2017 through December 31, 2017.
(b)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c)Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.
In 2017, PSEG made public propertysimilar financial challenges facing its New Jersey nuclear plants including Salem, of which Generation owns a 42.59% ownership interest. Although Salem is committed to operate through May 2021, the plant faces continued economic challenges and PSEG, as the operator of the plant, is exploring all options.
On May 23, 2018, the Governor of New Jersey signed new legislation, which became effective immediately, that will establish a ZEC program providing compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the new legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. The NJBPU has 180 days from the effective date to establish procedures for implementation of the ZEC program and 330 days from the effective date to determine which nuclear power plants are selected to receive ZECs under the program. Selected nuclear plants will receive ZEC payments for each energy year (12-month period from June 1 through May 31) within 90 days after the Districtcompletion of Columbiasuch energy year. Assuming the successful implementation of the New Jersey ZEC program and paid the Districtselection of Columbia $25 million. Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk of earlier retirement for Salem. See Note 6 — Regulatory Matters for additional information on the New Jersey ZEC program.

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

The specific sponsorship rights were to be determined over time through future negotiations. Asfollowing table provides the balance sheet amounts as of September 30, 2017, PHI has recorded2018 for Generation’s ownership share of the sponsorship agreementsignificant assets and liabilities associated with Salem that would potentially be impacted by a decision to permanently cease generation operations.
  September 30, 2018
Asset Balances  
Materials and supplies inventory $45
Nuclear fuel inventory, net 114
Completed plant, net 605
Construction work in progress 34
Liability Balances  
Asset retirement obligation (455)
   
NRC License Renewal Term 2036 (unit 1)
  2040 (unit 2)
On March 29, 2018, Generation announced it had formally notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets absent regulatory reforms on June 1, 2022, at the end of the current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 is currently committed through May 2021. Absent any regulatory reforms to properly value reliability and regional fuel security, these units will not participate in the Forward Capacity Auction (FCA) scheduled for February 2019 for the 2022 - 2023 capacity commitment period.
The ISO-NE announced that it would take a three-step approach to fuel security. First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel security for the 2022 - 2024 capacity commitment periods. Second, ISO-NE planned to file tariff revisions to allow it to retain other resources for fuel security in the capacity market if necessary in the future. Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot recover future operating costs, including the cost of procuring fuel.
On May 16, 2018, Generation made a finite-lived intangible assetfiling with a $25 million carrying amount. Because no specific sponsorship agreements have yet been entered intoFERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. Among the costs included in the filing are costs associated with the District of Columbia, amortizationDistrigas facility. Generation asked that FERC establish an expedited settlement process that would allow Generation to know the outcome of the finite-lived intangible asset has yetcost-of-service proceeding prior to commence.making a final decision as to whether to unconditionally retire the plants beginning June 1, 2022. A number of parties filed protests in response to the May 16, 2018 filing.
On July 2, 2018, FERC issued an order denying ISO-NE’s May 1, 2018 waiver request on procedural grounds but accepting ISO-NE’s conclusions that retirement of Mystic Units 8 and 9 could cause a violation of mandatory reliability standards as soon as 2022. Accordingly, FERC ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address demonstrated fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. FERC also extended the deadline by which Generation must make a retirement decision for Mystic Units 8 and 9 to January 4, 2019. In addition, notwithstanding its denial of the third quarter of 2017, PHI continued discussions with the District of Columbia regarding the nature and timing of available sponsorship opportunities, and based on these ongoing discussions,waiver request, FERC stated that it will continue to evaluate any potential impactMystic’s May 16, 2018 cost-of-service agreement filing. On August 31, 2018,

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

ISO-NE filed a compliance filing in response to FERC's July 2, 2018 order proposing short-term tariff changes to permit it to retain a resource for fuel security reliability reasons. A number of parties, including Generation, have submitted comments on the valuationproposal, which is pending before FERC.
On July 13, 2018, FERC issued an order accepting Generation’s cost-of-service agreement for filing and making findings on certain issues, including that recovery of fuel supply costs for the sponsorship intangible asset.Distrigas facility are not prohibited if they are just and reasonable. Additionally, the order established hearing procedures on an expedited schedule. Any settlement discussions are to be undertaken on a parallel track with the hearing. Generation has requested that FERC issue an order by December 21, 2018, but FERC is not obligated to meet this date.
Exelon and Generation cannot predict the final outcome of these proceedings or the potential financial impact, if any, on Exelon or Generation.
The following table provides the balance sheet amounts as of September 30, 2018 for Generation’s significant assets and liabilities associated with the Mystic Generating Station assets that would potentially be impacted by a decision to permanently cease generation operations.
  September 30, 2018
Asset Balances  
Materials and supplies inventory $21
Fuel inventory 18
Completed plant, net 877
Construction work in progress 5
Prepaid expenses(a)
 15
Liability Balances  
Asset retirement obligation (5)
Accrued expenses(a)
 (2)
_________
(a)Reflects ending balances only as they relate to Mystic's Long-term Service Agreement.
On October 1, 2018, Generation acquired the Distrigas liquefied natural gas import terminal to ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating.

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

9. Fair Value of Financial Assets and Liabilities (All Registrants)
Fair Value of Financial Liabilities Recorded at the Carrying AmountAmortized Cost
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of September 30, 20172018 and December 31, 2016:2017:
Exelon
September 30, 2017September 30, 2018
Carrying
Amount
 Fair Value
Carrying
Amount
 Fair Value
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Short-term liabilities(a)$710
 $—
 $710
 $—
 $710
$834
 $—
 $834
 $—
 $834
Long-term debt (including amounts due within one year)(a)(c)
34,865
 —
 34,686
 1,949
 36,635
35,290
 —
 33,608
 2,079
 35,687
Long-term debt to financing trusts(b)(d)
389
 —
 —
 423
 423
390
 —
 —
 411
 411
SNF obligation1,142
 —
 857
 —
 857
1,164
 —
 993
 —
 993
 December 31, 2017
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$929
 $—
 $929
 $—
 $929
Long-term debt (including amounts due within one year)(b)(c)
34,264
 —
 34,735
 1,970
 36,705
Long-term debt to financing trusts(d)
389
 —
 —
 431
 431
SNF obligation1,147
 —
 936
 —
 936
Generation
 September 30, 2018
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(b)(c)
$8,842
 $—
 $7,563
 $1,461
 $9,024
SNF obligation1,164
 —
 993
 —
 993
 December 31, 2017
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$2
 $—
 $2
 $—
 $2
Long-term debt (including amounts due within one year)(b)(c)
8,990
 —
 7,839
 1,673
 9,512
SNF obligation1,147
 —
 936
 —
 936

97
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

 December 31, 2016
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities$1,267
 $—
 $1,267
 $—
 $1,267
Long-term debt (including amounts due within one year)(a)
34,005
 1,113
 31,741
 1,959
 34,813
Long-term debt to financing trusts(b)
641
 —
 —
 667
 667
SNF obligation1,024
 —
 732
 —
 732
Generation
 September 30, 2017
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities$92
 $—
 $92
 $—
 $92
Long-term debt (including amounts due within one year)(a)
9,528
 —
 7,915
 1,652
 9,567
SNF obligation1,142
 —
 857
 —
 857
 December 31, 2016
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities$699
 $—
 $699
 $—
 $699
Long-term debt (including amounts due within one year)(a)
9,241
 —
 7,482
 1,670
 9,152
SNF obligation1,024
 —
 732
 —
 732
ComEd
September 30, 2017September 30, 2018
Carrying
Amount
 Fair Value
Carrying
Amount
 Fair Value
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)(c)
$7,600
 $—
 $8,353
 $—
 $8,353
8,100
 —
 8,317
 —
 8,317
Long-term debt to financing trusts(b)(d)
205
 —
 —
 226
 226
205
 —
 —
 214
 214
December 31, 2016December 31, 2017
Carrying
Amount
 Fair Value
Carrying
Amount
 Fair Value
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)(c)
$7,033
 $—
 $7,585
 $—
 $7,585
$7,601
 $—
 $8,418
 $—
 $8,418
Long-term debt to financing trusts(b)(d)
205
 —
 —
 215
 215
205
 —
 —
 227
 227
PECO
September 30, 2017September 30, 2018
Carrying
Amount
 Fair Value
Carrying
Amount
 Fair Value
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)(c)
$2,902
 $—
 $3,181
 $—
 $3,181
3,083
 —
 3,130
 50
 3,180
Long-term debt to financing trusts184
 —
 —
 197
 197
184
 —
 —
 196
 196
 December 31, 2017
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(b)(c)
$2,903
 $—
 $3,194
 $—
 $3,194
Long-term debt to financing trusts184
 —
 —
 204
 204
BGE
 September 30, 2018
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(b)(c)
2,876
 —
 2,933
 —
 2,933
 December 31, 2017
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$77
 $—
 $77
 $—
 $77
Long-term debt (including amounts due within one year)(b)(c)
2,577
 —
 2,825
 —
 2,825

98
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

 December 31, 2016
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)
$2,580
 $—
 $2,794
 $—
 $2,794
Long-term debt to financing trusts184
 —
 —
 192
 192
BGEPHI
 September 30, 2017
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)
$2,577
 $—
 $2,817
 $—
 $2,817
 September 30, 2018
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$334
 $—
 $334
 $—
 $334
Long-term debt (including amounts due within one year)(b)(c)
6,089
 —
 5,323
 568
 5,891
 December 31, 2016
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities$45
 $—
 $45
 $—
 $45
Long-term debt (including amounts due within one year)(a)
2,322
 —
 2,467
 —
 2,467
Long-term debt to financing trusts(b)
252
 —
 —
 260
 260
PHI (Successor)
 September 30, 2017
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities$118
 $—
 $118
 $—
 $118
Long-term debt (including amounts due within one year)(a)
5,930
 —
 5,729
 297
 6,026
December 31, 2016December 31, 2017
Carrying Amount Fair ValueCarrying Amount Fair Value
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Short-term liabilities(a)$522
 $—
 $522
 $—
 $522
$350
 $—
 $350
 $—
 $350
Long-term debt (including amounts due within one year)(a)(c)
5,898
 —
 5,520
 289
 5,809
5,874
 —
 5,722
 297
 6,019
Pepco
 September 30, 2017
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)
$2,546
 $—
 $3,087
 $9
 $3,096
 September 30, 2018
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$64
 $—
 $64
 $—
 $64
Long-term debt (including amounts due within one year)(b)(c)
$2,625
 $—
 $2,890
 $101
 $2,991
December 31, 2016December 31, 2017
Carrying Amount Fair ValueCarrying Amount Fair Value
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Short-term liabilities(a)$23
 $—
 $23
 $—
 $23
$26
 $—
 $26
 $—
 $26
Long-term debt (including amounts due within one year)(a)(c)
2,349
 —
 2,788
 8
 2,796
2,540
 —
 3,114
 9
 3,123
DPL
 September 30, 2018
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(b)(c)
$1,494
 $—
 $1,299
 $196
 $1,495
 December 31, 2017
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$216
 $—
 $216
 $—
 $216
Long-term debt (including amounts due within one year)(b)(c)
1,300
 —
 1,393
 —
 1,393

99
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

DPL
 September 30, 2017
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities$54
 $—
 $54
 $—
 $54
Long-term debt (including amounts due within one year)(a)
1,326
 —
 1,407
 —
 1,407
 December 31, 2016
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)
$1,340
 $—
 $1,383
 $—
 $1,383
ACE
September 30, 2017September 30, 2018
Carrying Amount Fair ValueCarrying Amount Fair Value
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Short-term liabilities(a)$65
 $—
 $65
 $—
 $65
$270
 $—
 $270
 $—
 $270
Long-term debt (including amounts due within one year)(a)(c)
1,130
 —
 969
 288
 1,257
1,100
 —
 887
 271
 1,158
 December 31, 2016
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)
$1,155
 $—
 $1,007
 $280
 $1,287
 December 31, 2017
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$108
 $—
 $108
 $—
 $108
Long-term debt (including amounts due within one year)(b)(c)
1,121
 —
 949
 288
 1,237
_________
(a)
Level 1 securities consist of dividends payable (included in other current liabilities). Level 2 securities consist of short term borrowings.
(b)Includes unamortized debt issuance costs which are not fair valued of $196$219 million, $51$53 million, $53$64 million, $23 million, $19 million, $11 million, $34 million, $12 million and $4 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of September 30, 2018. Includes unamortized debt issuance costs which are not fair valued of $201 million, $60 million, $52 million, $17 million, $17 million, $6 million,, $32 $32 million, $11 million and $5 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of September 30, 2017. 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, 2016.2017.
(b)(c)Level 2 securities consist of fixed-rate taxable debt securities, fixed-rate tax-exempt debt, variable rate tax-exempt debt and variable rate non-recourse debt. Level 3 securities consist of fixed-rate private placement taxable debt securities, fixed rate nonrecourse debt, government-backed fixed rate non-recourse debt and loan agreements.
(d)Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of September 30, 2017. Includes unamortized debt issuance costs which are not fair valued of $7 million, $1 million,2018 and $6 million for Exelon, ComEd and BGE, respectively, as of December 31, 2016.2017.
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, 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 and Pepco's non-government-backed fixed rate nonrecourse debt (Level 3) is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project

100
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

cash flows or off-taker credit, and other circumstances related to the project (e.g., political and regulatory environment). The fair value of Generation’s government-backed fixed rate project financing debt (Level 3) is largely based on a discounted cash flow methodology that is similar to the taxable debt securities methodology described above. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable Treasury rate as well as a current market curve derived from government-backed securities. Variable rate financing debt resets on a monthly or quarterly basis and the carrying value approximates fair value (Level 2). When trading data is available on variable rate financing debt, the fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles (Level 2).  Generation, Pepco, DPL and ACE also have tax-exempt debt (Level 2). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (e.g., conduit issuer political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. Variable rate tax-exempt debt (Level 2) resets on a regular basis and the carrying value approximates fair value.
SNF Obligation. The carrying amount of Generation’s SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2030. The carrying amount also includes $112 million as of September 30, 2017 for the one-time fee obligation associated with closing of the FitzPatrick acquisition on March 31, 2017. The fair value was determined using a similar methodology, however the New York Power Authority's (NYPA) discount rate is used in place of Generation's given the contractual right to reimbursement from NYPA for the obligation; see Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.
Long-Term Debt to Financing Trusts. Exelon’s long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.
Recurring Fair Value Measurements
Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
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 material transfers between Level 1 and Level 2 during the nine months ended September 30, 20172018 for cash equivalents, nuclear decommissioning trust fund investments, pledgedPledged assets for Zion Station decommissioning, Rabbi trust investments, and deferredDeferred 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.

101
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

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.
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 September 30, 20172018 and December 31, 2016:2017:
Generation ExelonGeneration Exelon
As of September 30, 2017Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
As of September 30, 2018Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
Assets                                      
Cash equivalents(a)
$80
 $—
 $—
 $—
 $80
 $944
 $—
 $—
 $—
 $944
$1,099
 $—
 $—
 $—
 $1,099
 $1,906
 $—
 $—
 $—
 $1,906
NDT fund investments        
         
        
         
Cash equivalents(b)
149
 86
 —
 —
 235
 149
 86
 —
 —
 235
278
 92
 —
 —
 370
 278
 92
 —
 —
 370
Equities3,935
 840
 —

2,088
 6,863
 3,935
 840
 —

2,088
 6,863
3,206
 1,608
 1

1,942
 6,757
 3,206
 1,608
 1

1,942
 6,757
Fixed income                                      
Corporate debt—
 1,651
 255
 —
 1,906
 —
 1,651
 255
 —
 1,906
—
 1,629
 231
 —
 1,860
 —
 1,629
 231
 —
 1,860
U.S. Treasury and agencies1,951
 28
 —
 —
 1,979
 1,951
 28
 —
 —
 1,979
2,031
 99
 —
 —
 2,130
 2,031
 99
 —
 —
 2,130
Foreign governments—
 70
 —
 —
 70
 —
 70
 —
 —
 70
—
 49
 —
 —
 49
 —
 49
 —
 —
 49
State and municipal debt—
 246
 —
 —
 246
 —
 246
 —
 —
 246
—
 165
 —
 —
 165
 —
 165
 —
 —
 165
Other(c)
—
 46
 —
 509
 555
 —
 46
 —
 509
 555
—
 29
 —
 854
 883
 —
 29
 —
 854
 883
Fixed income subtotal1,951

2,041

255
 509

4,756

1,951

2,041

255
 509

4,756
2,031

1,971

231
 854

5,087

2,031

1,971

231
 854

5,087
Middle market lending—
 —
 416
 87
 503
 —
 —
 416
 87
 503
—
 —
 334
 235
 569
 —
 —
 334
 235
 569
Private equity—
 —
 —
 212
 212
 —
 —
 —
 212
 212
—
 —
 —
 303
 303
 —
 —
 —
 303
 303
Real estate—
 —
 —
 449
 449
 —
 —
 —
 449
 449
—
 —
 —
 490
 490
 —
 —
 —
 490
 490
NDT fund investments subtotal(d)
6,035

2,967

671
 3,345

13,018

6,035

2,967

671
 3,345

13,018
5,515

3,671

566
 3,824

13,576

5,515

3,671

566
 3,824

13,576
Pledged assets for Zion Station decommissioning                                      
Cash equivalents15
 —
 —
 —
 15
 15
 —
 —
 —
 15
9
 —
 —
 —
 9
 9
 —
 —
 —
 9
Pledged assets for Zion Station
decommissioning subtotal(e)
9

—

—
 —

9

9

—

—
 —

9
Rabbi trust investments        
         
Cash equivalents5
 —
 —
 —
 5
 48
 —
 —
 —
 48
Mutual funds25
 —
 —
 —
 25
 76
 —
 —
 —
 76
Fixed income—
 —
 —
 —
 —
 —
 16
 —
 —
 16
Life insurance contracts—
 23
 —
 —
 23
 —
 73
 37
 —
 110
Rabbi trust investments subtotal(f)
30

23

—
 —

53

124

89

37
 —

250

102
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Generation ExelonGeneration Exelon
As of September 30, 2017Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
Middle market lending—
 —
 17
 25
 42
 —
 —
 17
 25
 42
Pledged assets for Zion Station
decommissioning subtotal(e)
15

—

17
 25

57

15

—

17
 25

57
Rabbi trust investments        
         
Cash equivalents5
 —
 —
 —
 5
 77
 —
 —
 —
 77
Mutual funds22
 —
 —
 —
 22
 56
 —
 —
 —
 56
Fixed income—
 —
 —
 —
 —
 —
 13
 —
 —
 13
Life insurance contracts—
 21
 —
 —
 21
 —
 68
 21
 —
 89
Rabbi trust investments subtotal27

21

—
 —

48

133

81

21
 —

235
As of September 30, 2018Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
Commodity derivative assets                                      
Economic hedges487
 2,076
 1,628
 —
 4,191
 487
 2,076
 1,628
 —
 4,191
234
 2,117
 2,019
 —
 4,370
 234
 2,117
 2,019
 —
 4,370
Proprietary trading2
 41
 42
 —
 85
 2
 41
 42
 —
 85
—
 84
 90
 —
 174
 —
 84
 90
 —
 174
Effect of netting and allocation of collateral(f) (g)
(501) (1,828) (837) —
 (3,166) (501) (1,828) (837) —
 (3,166)
Effect of netting and allocation of collateral(g) (h)
(230) (1,887) (1,302) —
 (3,419) (230) (1,887) (1,302) —
 (3,419)
Commodity derivative assets subtotal(12)
289

833
 —

1,110

(12)
289

833
 —

1,110
4

314

807
 —

1,125

4

314

807
 —

1,125
Interest rate and foreign currency derivative assets                                      
Derivatives designated as hedging instruments—
 —
 —
 —
 —
 —
 10
 —
 —
 10
—
 —
 —
 —
 —
 —
 —
 —
 —
 —
Economic hedges3
 13
 —
 —
 16
 3
 13
 —
 —
 16
—
 21
 —
 —
 21
 —
 21
 —
 —
 21
Effect of netting and allocation of collateral(3) (8) —
 —
 (11) (3) (8) —
 —
 (11)—
 (1) —
 —
 (1) —
 (1) —
 —
 (1)
Interest rate and foreign currency derivative assets subtotal—

5

—
 —

5

—

15

—
 —

15
—

20

—
 —

20

—

20

—
 —

20
Other investments—
 —
 43
 —
 43
 —
 —
 43
 —
 43
—
 —
 52
 —
 52
 —
 —
 52
 —
 52
Total assets6,145

3,282

1,564

3,370

14,361

7,115

3,352

1,585

3,370

15,422
6,657

4,028

1,425

3,824

15,934

7,558

4,094

1,462

3,824

16,938
Liabilities                                      
Commodity derivative liabilities                                      
Economic hedges(559) (2,062) (1,189) —
 (3,810) (559) (2,062) (1,466) —
 (4,087)(329) (2,056) (1,660) —
 (4,045) (329) (2,056) (1,919) —
 (4,304)
Proprietary trading(3) (43) (27) —
 (73) (3) (43) (27) —
 (73)—
 (95) (32) —
 (127) —
 (95) (32) —
 (127)
Effect of netting and allocation of collateral(f) (g)
560
 2,043
 978
 —
 3,581
 560
 2,043
 978
 —
 3,581
Effect of netting and allocation of collateral(g) (h)
247
 1,987
 1,397
 —
 3,631
 247
 1,987
 1,397
 —
 3,631
Commodity derivative liabilities subtotal(2) (62) (238) —
 (302) (2) (62) (515) —
 (579)(82) (164) (295) —
 (541) (82) (164) (554) —
 (800)
Interest rate and foreign currency derivative liabilities                                      
Derivatives designated as hedging instruments—
 —
 —
 —
 —
 —
 (10) —
 —
 (10)
Economic hedges(2) (17) —
 —
 (19) (2) (17) —
 —
 (19)—
 (2) —
 —
 (2) —
 (2) —
 —
 (2)
Effect of netting and allocation of collateral2
 8
 —
 —
 10
 2
 8
 —
 —
 10
—
 1
 —
 —
 1
 —
 1
 —
 —
 1
Interest rate and foreign currency derivative liabilities subtotal—

(9)
—
 —

(9)
—

(9)
—
 —

(9)—

(1)
—
 —

(1)
—

(11)
—
 —

(11)
Deferred compensation obligation—
 (35) —
 —
 (35) —
 (137) —
 —
 (137)—
 (36) —
 —
 (36) —
 (142) —
 —
 (142)
Total liabilities(2)
(106)
(238) —

(346)
(2)
(208)
(515) —

(725)(82)
(201)
(295) —

(578)
(82)
(317)
(554) —

(953)
Total net assets$6,143

$3,176

$1,326
 $3,370

$14,015

$7,113

$3,144

$1,070
 $3,370

$14,697
$6,575

$3,827

$1,130
 $3,824

$15,356

$7,476

$3,777

$908
 $3,824

$15,985

103
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Generation ExelonGeneration Exelon
As of December 31, 2016Level 1 Level 2 Level 3 Not subject to leveling Total Level 1
Level 2
Level 3 Not subject to leveling
Total
As of December 31, 2017Level 1 Level 2 Level 3 Not subject to leveling Total Level 1
Level 2
Level 3 Not subject to leveling
Total
Assets                                      
Cash equivalents(a)
$39
 $—
 $—
 $—
 $39
 $373
 $—
 $—
 $—
 $373
$168
 $—
 $—
 $—
 $168
 $656
 $—
 $—
 $—
 $656
NDT fund investments                  

                  

Cash equivalents(b)
110
 19
 —
 —
 129
 110
 19
 —
 —
 129
135
 85
 —
 —
 220
 135
 85
 —
 —
 220
Equities3,551

452

—

2,011

6,014

3,551

452

—

2,011

6,014
4,163

915

—

2,176

7,254

4,163

915

—

2,176

7,254
Fixed income                                      
Corporate debt—
 1,554
 250
 —
 1,804
 —
 1,554
 250
 —
 1,804
—
 1,614
 251
 —
 1,865
 —
 1,614
 251
 —
 1,865
U.S. Treasury and agencies1,291
 29
 —
 —
 1,320
 1,291
 29
 —
 —
 1,320
1,917
 52
 —
 —
 1,969
 1,917
 52
 —
 —
 1,969
Foreign governments—
 37
 —
 —
 37
 —
 37
 —
 —
 37
—
 82
 —
 —
 82
 —
 82
 —
 —
 82
State and municipal debt—
 264
 —
 —
 264
 —
 264
 —
 —
 264
—
 263
 —
 —
 263
 —
 263
 —
 —
 263
Other(c)
—
 59
 —
 493
 552
 —
 59
 —
 493
 552
—
 47
 —
 510
 557
 —
 47
 —
 510
 557
Fixed income subtotal1,291

1,943

250
 493

3,977

1,291

1,943

250
 493

3,977
1,917

2,058

251
 510

4,736

1,917

2,058

251
 510

4,736
Middle market lending—
 —
 427
 71
 498
 —
 —
 427
 71
 498
—
 —
 397
 131
 528
 —
 —
 397
 131
 528
Private equity—
 —
 —
 148
 148
 —
 —
 —
 148
 148
—
 —
 —
 222
 222
 —
 —
 —
 222
 222
Real estate—
 —
 —
 326
 326
 —
 —
 —
 326
 326
—
 —
 —
 471
 471
 —
 —
 —
 471
 471
NDT fund investments subtotal(d)
4,952

2,414

677
 3,049

11,092

4,952

2,414

677
 3,049
 11,092
6,215

3,058

648
 3,510

13,431

6,215

3,058

648
 3,510
 13,431
Pledged assets for Zion Station decommissioning                                      
Cash equivalents11
 —
 —
 —
 11
 11
 —
 —
 —
 11
2
 —
 —
 —
 2
 2
 —
 —
 —
 2
Equities—
 2
 —
 —
 2
 —
 2
 —
 —
 2
—
 1
 —
 —
 1
 —
 1
 —
 —
 1
Fixed Income - U.S. Treasury and agencies16
 1
 —
 —
 17
 16
 1
 —
 —
 17
Middle market lending—
 —
 19
 64
 83
 —
 —
 19
 64
 83
—
 —
 12
 24
 36
 —
 —
 12
 24
 36
Pledged assets for Zion Station decommissioning subtotal(e)
27

3

19
 64

113

27

3

19
 64

113
2

1

12
 24

39

2

1

12
 24

39
Rabbi trust investments                                      
Cash equivalents2
 —
 —
 —
 2
 74
 —
 —
 —
 74
5
 —
 —
 —
 5
 77
 —
 —
 —
 77
Mutual funds19
 —
 —
 —
 19
 50
 —
 —
 —
 50
23
 —
 —
 —
 23
 58
 —
 —
 —
 58
Fixed income—
 —
 —
 —
 —
 —
 16
 —
 —
 16
—
 —
 —
 —
 —
 —
 12
 —
 —
 12
Life insurance contracts—
 18
 —
 —
 18
 —
 64
 20
 —
 84
—
 22
 —
 —
 22
 —
 71
 22
 —
 93
Rabbi trust investments subtotal21

18

—
 —

39

124

80

20
 —

224
Rabbi trust investments subtotal(f)
28

22

—
 —

50

135

83

22
 —

240
Commodity derivative assets                                      
Economic hedges1,356
 2,505
 1,229
 —
 5,090
 1,358
 2,505
 1,229
 —
 5,092
557
 2,378
 1,290
 —
 4,225
 557
 2,378
 1,290
 —
 4,225
Proprietary trading3
 50
 23
 —
 76
 3
 50
 23
 —
 76
2
 31
 35
 —
 68
 2
 31
 35
 —
 68
Effect of netting and allocation of collateral(f) (g)
(1,162) (2,142) (481) —
 (3,785) (1,164) (2,142) (481) —
 (3,787)
Effect of netting and allocation of collateral(g) (h)
(585) (1,769) (635) —
 (2,989) (585) (1,769) (635) —
 (2,989)
Commodity derivative assets subtotal197

413

771
 —

1,381

197

413

771
 —

1,381
(26)
640

690
 —

1,304

(26)
640

690
 —

1,304
Interest rate and foreign currency derivative assets        

         

Derivatives designated as hedging instruments—
 —
 —
 —
 —
 —
 16
 —
 —
 16
Economic hedges—
 28
 —
 —
 28
 —
 28
 —
 —
 28
Proprietary trading3
 2
 —
 —
 5
 3
 2
 —
 —
 5
Effect of netting and allocation of collateral(2) (19) —
 —
 (21) (2) (19) —
 —
 (21)
Interest rate and foreign currency derivative assets subtotal1

11

—
 —

12

1

27

—
 —

28
Other investments—
 —
 42
 —
 42
 —
 —
 42
 —
 42
Total assets5,237

2,859

1,509
 3,113

12,718

5,674

2,937

1,529
 3,113

13,253

104
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Generation ExelonGeneration Exelon
As of December 31, 2016Level 1 Level 2 Level 3 Not subject to leveling Total Level 1
Level 2
Level 3 Not subject to leveling
Total
As of December 31, 2017Level 1 Level 2 Level 3 Not subject to leveling Total Level 1
Level 2
Level 3 Not subject to leveling
Total
Interest rate and foreign currency derivative assets        

         

Derivatives designated as hedging instruments—
 3
 —
 —
 3
 —
 6
 —
 —
 6
Economic hedges—
 10
 —
 —
 10
 —
 10
 —
 —
 10
Effect of netting and allocation of collateral(2) (5) —
 —
 (7) (2) (5) —
 —
 (7)
Interest rate and foreign currency derivative assets subtotal(2)
8

—
 —

6

(2)
11

—
 —

9
Other investments—
 —
 37
 —
 37
 —
 —
 37
 —
 37
Total assets6,385

3,729

1,387
 3,534

15,035

6,980

3,793

1,409
 3,534

15,716
Liabilities        
         
        
         
Commodity derivative liabilities                                      
Economic hedges(1,267) (2,378) (794) —
 (4,439) (1,267) (2,378) (1,052) —
 (4,697)(712) (2,226) (845) —
 (3,783) (713) (2,226) (1,101) —
 (4,040)
Proprietary trading(3) (50) (26) —
 (79) (3) (50) (26) —
 (79)(2) (42) (9) —
 (53) (2) (42) (9) —
 (53)
Effect of netting and allocation of collateral(f) (g)
1,233
 2,339
 542
 —
 4,114
 1,233
 2,339
 542
 —
 4,114
Effect of netting and allocation of collateral(g) (h)
650
 2,089
 716
 —
 3,455
 651
 2,089
 716
 —
 3,456
Commodity derivative liabilities subtotal(37)
(89)
(278) —

(404)
(37)
(89)
(536) —

(662)(64)
(179)
(138) —

(381)
(64)
(179)
(394) —

(637)
Interest rate and foreign currency derivative liabilities                                      
Derivatives designated as hedging instruments—
 (10) —
 —
 (10) —
 (10) —
 —
 (10)—
 (2) —
 —
 (2) —
 (2) —
 —
 (2)
Economic hedges—
 (21) —
 —
 (21) —
 (21) —
 —
 (21)(1) (8) —
 —
 (9) (1) (8) —
 —
 (9)
Proprietary trading(4) —
 —
 —
 (4) (4) —
 —
 —
 (4)
Effect of netting and allocation of collateral4
 19
 —
 —
 23
 4
 19
 —
 —
 23
2
 5
 —
 —
 7
 2
 5
 —
 —
 7
Interest rate and foreign currency derivative liabilities subtotal—

(12)
—
 —

(12)
—

(12)
—
 —

(12)1

(5)
—
 —

(4)
1

(5)
—
 —

(4)
Deferred compensation obligation—
 (34) —
 —
 (34) —
 (136) —
 —
 (136)—
 (38) —
 —
 (38) —
 (145) —
 —
 (145)
Total liabilities(37)
(135)
(278) —

(450)
(37)
(237)
(536) —

(810)(63)
(222)
(138) —

(423)
(63)
(329)
(394) —

(786)
Total net assets$5,200

$2,724

$1,231
 $3,113

$12,268

$5,637

$2,700

$993
 $3,113

$12,443
$6,322

$3,507

$1,249
 $3,534

$14,612

$6,917

$3,464

$1,015
 $3,534

$14,930
_________
(a)Generation excludes cash of $282$183 million and $252$259 million at September 30, 20172018 and December 31, 20162017 and restricted cash of $184$57 million and $157$127 million at September 30, 20172018 and December 31, 2016.2017.  Exelon excludes cash of $382$330 million and $360$389 million at September 30, 20172018 and December 31, 20162017 and restricted cash of $219$85 million and $180$145 million at September 30, 20172018 and December 31, 20162017 and includes long-term restricted cash of $22$163 million and $25$85 million at September 30, 20172018 and December 31, 2016,2017, which is reported in otherOther deferred debits on the balance sheet.Consolidated Balance Sheets.
(b)Includes $75$37 million and $29$77 million of cash received from outstanding repurchase agreements at September 30, 20172018 and December 31, 2016,2017, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.
(c)Includes derivative instruments of $(4) million and less than $1 million and $(2) million, which have a total notional amount of $885$915 million and $933$811 million at September 30, 20172018 and December 31, 2016,2017, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company'sExelon and Generation's exposure to credit or market loss.
(d)Excludes net liabilities of $52$89 million and $31$82 million at September 30, 20172018 and December 31, 2016,2017, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.
(e)Excludes net assets of less than $1 million at September 30, 2017 and December 31, 2016.2018. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
(f)Collateral posted/(received) from counterparties totaled $59 million, $215 million and $141 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2017. Collateral posted/(received) from counterparties, net of collateral paid to 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.
(g)Of the collateral posted/(received), $27 million represents variation margin on the exchanges as of September 30, 2017. Of the collateral posted/(received), $(158) million represents variation margin on the exchanges as of December 31, 2016.

105
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

(f)The amount of unrealized gains/(losses) at Generation totaled less than $1 million for the three months ended September 30, 2018 and September 30, 2017. The amount of unrealized gains/(losses) at Generation totaled less than $1 million and $1 million for the nine months ended September 30, 2018 and September 30, 2017, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million for the three months ended September 30, 2018 and September 30, 2017. The amount of unrealized gains/(losses) at Exelon totaled $2 million and $3 million for the nine months ended September 30, 2018 and September 30, 2017, respectively.
(g)Collateral posted/(received) from counterparties totaled $18 million, $100 million and $94 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2018. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $65 million, $320 million and $81 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2017.
(h)Of the collateral posted/(received), $(166) million represents variation margin on the exchanges as of September 30, 2018. Of the collateral posted/(received), $(117) million represents variation margin on the exchanges as of December 31, 2017.
Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $71 million as of September 30, 2018. Changes were immaterial in fair value, cumulative adjustments and impairments for the three and nine months ended September 30, 2018.
ComEd, PECO and BGE
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 September 30, 20172018 and December 31, 2016:2017:
ComEd PECO BGEComEd PECO BGE
As of September 30, 2017Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
As of September 30, 2018Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets                                              
Cash equivalents(a)
$273
 $—
 $—
 $273
 $314
 $—
 $—
 $314
 $18
 $—
 $—
 $18
$211
 $—
 $—
 $211
 $84
 $—
 $—
 $84
 $100
 $—
 $—
 $100
Rabbi trust investments      
       
       
      
       
       
Mutual funds—
 —
 —
 —
 7
 —
 —
 7
 5
 —
 —
 5
—
 —
 —
 —
 7
 —
 —
 7
 6
 —
 —
 6
Life insurance contracts—
 —
 —
 —
 —
 10
 —
 10
 —
 —
 —
 —
—
 —
 —
 —
 —
 11
 —
 11
 —
 —
 —
 —
Rabbi trust investments subtotal(b)—

—

—

—

7

10

—

17

5

—

—

5
—

—

—

—

7

11

—

18

6

—

—

6
Total assets273

—

—

273

321

10

—

331

23

—

—

23
211

—

—

211

91

11

—

102

106

—

—

106
Liabilities      
       
       
      
       
       
Deferred compensation obligation—
 (7) —
 (7) —
 (10) —
 (10) —
 (4) —
 (4)—
 (7) —
 (7) —
 (10) —
 (10) —
 (5) —
 (5)
Mark-to-market derivative liabilities(b)(c)
—
 —
 (277) (277) —
 —
 —
 —
 —
 —
 —
 —
—
 —
 (259) (259) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (7) (277) (284) —
 (10) —
 (10) —
 (4) —
 (4)—
 (7) (259) (266) —
 (10) —
 (10) —
 (5) —
 (5)
Total net assets (liabilities)$273
 $(7) $(277) $(11) $321
 $—
 $—
 $321
 $23
 $(4) $—
 $19
$211
 $(7) $(259) $(55) $91
 $1
 $—
 $92
 $106
 $(5) $—
 $101

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

ComEd PECO BGEComEd PECO BGE
As of December 31, 2016Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
As of December 31, 2017Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets                                              
Cash equivalents(a)
$20
 $—
 $—
 $20
 $45
 $—
 $—
 $45
 $36
 $—
 $—
 $36
$98
 $—
 $—
 $98
 $228
 $—
 $—
 $228
 $—
 $—
 $—
 $—
Rabbi trust investments      
       
       
      
       
       
Mutual funds—
 —
 —
 —
 7
 —
 —
 7
 4
 —
 —
 4
—
 —
 —
 —
 7
 —
 —
 7
 6
 —
 —
 6
Life insurance contracts—
 —
 —
 —
 —
 10
 —
 10
 —
 —
 —
 —
—
 —
 —
 —
 —
 10
 —
 10
 —
 —
 —
 —
Rabbi trust investments subtotal(b)—

—

—

—

7

10

—

17

4

—

—

4
—

—

—

—

7

10

—

17

6

—

—

6
Total assets20

—

—

20

52

10

—

62

40

—

—

40
98

—

—

98

235

10

—

245

6

—

—

6
Liabilities      
       
       
      
       
       
Deferred compensation obligation—
 (8) —
 (8) —
 (11) —
 (11) —
 (4) —
 (4)—
 (8) —
 (8) —
 (11) —
 (11) —
 (5) —
 (5)
Mark-to-market derivative liabilities(b)(c)
—
 —
 (258) (258) —
 —
 —
 —
 —
 —
 —
 —
—
 —
 (256) (256) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (8) (258) (266) —
 (11) —
 (11) —
 (4) —
 (4)—
 (8) (256) (264) —
 (11) —
 (11) —
 (5) —
 (5)
Total net assets (liabilities)$20
 $(8) $(258) $(246) $52
 $(1) $—
 $51
 $40
 $(4) $—
 $36
$98
 $(8) $(256) $(166) $235
 $(1) $—
 $234
 $6
 $(5) $—
 $1
_________
(a)ComEd excludes cash of $36$69 million and $45 million at September 30, 20172018 and December 31, 2016 and restricted cash of $2 million at December 31, 2016.  PECO excludes cash of $20 million and $22 million at September 30, 2017 and December 31, 2016.  BGE excludes cash of $11 million and $13 million at September 30, 2017 and December 31, 2016 and restricted cash of $1 million at September 30, 2017 and includes long-term restricted cash of $2$144 million and $62 million at September 30, 2018 and December 31, 2016,2017, which is reported in otherOther deferred debits on the balance sheet.Consolidated Balance Sheets.  PECO excludes cash of $23 million and $47 million at September 30, 2018 and December 31, 2017.  BGE excludes cash of $13 million and $17 million at September 30, 2018 and December 31, 2017 and restricted cash of $3 million and $1 million at September 30, 2018 and December 31, 2017.
(b)The amount of unrealized gains/(losses) at ComEd, PECO and BGE totaled less than $1 million for the three and nine months ended September 30, 2018 and September 30, 2017, respectively.
(c)The Level 3 balance consists of the current and noncurrent liability of $20$24 million and $257$235 million, respectively, at September 30, 2017,2018, and $19$21 million and $239$235 million, respectively, at December 31, 2016,2017, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

106
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

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 September 30, 20172018 and December 31, 2016:2017:
Successor 
As of September 30, 2017 As of December 31, 2016As of September 30, 2018 As of December 31, 2017
PHILevel 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets                              
Cash equivalents(a)
$184
 $—
 $—
 $184
 $217
 $—
 $—
 $217
$182
 $—
 $—
 $182
 $83
 $—
 $—
 $83
Mark-to-market derivative assets(b)
—
 —
 —
 —
 2
 —
 —
 2
Effect of netting and allocation of collateral—
 —
 —
 —
 (2) —
 —
 (2)
Mark-to-market derivative assets subtotal—
 —
 —
 —
 —
 —
 —
 —
Rabbi trust investments      
       
      
       
Cash equivalents72
 —
 —
 72
 73
 —
 —
 73
42
 —
 —
 42
 72
 —
 —
 72
Mutual funds15
 —
 —
 15
 —
 —
 —
 —
Fixed income—
 13
 —
 13
 —
 16
 —
 16
—
 16
 —
 16
 —
 12
 —
 12
Life insurance contracts—
 23
 21
 44
 —
 22
 20
 42
—
 22
 37
 59
 —
 23
 22
 45
Rabbi trust investments subtotal72

36

21

129

73

38

20

131
Rabbi trust investments subtotal(b)
57

38

37

132

72

35

22

129
Total assets256

36

21

313
 290

38

20

348
239

38

37

314
 155

35

22

212
Liabilities      
       
      
       
Deferred compensation obligation—
 (24) —
 (24) —
 (28) —
 (28)—
 (22) —
 (22) —
 (25) —
 (25)
Mark-to-market derivative liabilities(c)
—
 —
 —
 —
 (1) —
 —
 (1)
Effect of netting and allocation of collateral—
 —
 —
 —
 1
 —
 —
 1
Mark-to-market derivative liabilities subtotal—

—

—

—

—

—

—

—
Total liabilities—

(24)
—

(24)
—

(28)
—

(28)—

(22)
—

(22)
—

(25)
—

(25)
Total net assets$256

$12

$21

$289
 $290

$10

$20

$320
$239

$16

$37

$292
 $155

$10

$22

$187
Pepco DPL ACEPepco DPL ACE
As of September 30, 2017Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
As of September 30, 2018Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
 
 
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 
 
 
Cash equivalents(a)
$144
 $—
 $—
 $144
 $—
 $—
 $—
 $—
 $31
 $—
 $—
 $31
$35
 $—
 $—
 $35
 $102
 $—
 $—
 $102
 $26
 $—
 $—
 $26
Rabbi trust investments
 
 
   
 
 
   
 
 
                         
Cash equivalents43
 —
 —
 43
 —
 —
 —
 —
 —
 —
 —
 —
41
 —
 —
 41
 —
 —
 —
 —
 —
 —
 —
 —
Fixed income—
 13
 —
 13
 —
 —
 —
 —
 —
 —
 —
 —
—
 6
 —
 6
 —
 —
 —
 —
 —
 —
 —
 —
Life insurance contracts—
 23
 21
 44
 —
 —
 —
 —
 —
 —
 —
 —
—
 22
 36
 58
 —
 —
 —
 —
 —
 —
 —
 —
Rabbi trust investments subtotal(b)43

36

21

100

—

—

—

—

—

—

—

—
41

28

36

105

—

—

—

—

—

—

—

—
Total assets187

36

21

244

—

—

—

—

31

—

—

31
76

28

36

140

102

—

—

102

26

—

—

26
Liabilities
 
 
 

 
 
 
 
 
 
 
 

 
 
 

 
 
 
 
 
 
 
 
Deferred compensation obligation—
 (4) —
 (4) —
 (1) —
 (1) —
 —
 —
 —
—
 (3) —
 (3) —
 (1) —
 (1) —
 —
 —
 —
Total liabilities—

(4)
—

(4)
—

(1)
—

(1)
—

—

—

—
—

(3)
—

(3)
—

(1)
—

(1)
—

—

—

—
Total net assets (liabilities)$187
 $32
 $21
 $240
 $—
 $(1) $—
 $(1) $31
 $—
 $—
 $31
$76
 $25
 $36
 $137
 $102
 $(1) $—
 $101
 $26
 $—
 $—
 $26

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


Pepco DPL ACEPepco DPL ACE
As of December 31, 2016Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
As of December 31, 2017Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
 
 
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 
 
 
Cash equivalents(a)
$33
 $—
 $—
 $33
 $42
 $—
 $—
 $42
 $130
 $—
 $—
 $130
$36
 $—
 $—
 $36
 $—
 $—
 $—
 $—
 $29
 $—
 $—
 $29
Mark-to-market derivative assets(b)
—
 —
 —
 —
 2
 —
 —
 2
 —
 —
 —
 —
Effect of netting and allocation of collateral—
 —
 —
 —
 (2) —
 —
 (2) —
 —
 —
 —
Mark-to-market derivative assets subtotal—
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Rabbi trust investments                                              
Cash equivalents43
 —
 —
 43
 —
 —
 —
 —
 —
 —
 —
 —
44
 —
 —
 44
 —
 —
 —
 —
 —
 —
 —
 —
Fixed income—
 16
 —
 16
 —
 —
 —
 —
 —
 —
 —
 —
—
 12
 —
 12
 —
 —
 —
 —
 —
 —
 —
 —
Life insurance contracts—
 22
 19
 41
 —
 —
 —
 —
 —
 —
 —
 —
—
 23
 22
 45
 —
 —
 —
 —
 —
 —
 —
 —
Rabbi trust investments subtotal43

38

19

100

—

—

—

—

—

—

—

—
Rabbi trust investments subtotal(b)
44

35

22

101

—

—

—

—

—

—

—

—
Total assets76

38

19

133

42

—

—

42

130

—

—

130
80

35

22

137

—

—

—

—

29

—

—

29
Liabilities                                              
Deferred compensation obligation—
 (5) —
 (5) —
 (1) —
 (1) —
 —
 —
 —
—
 (4) —
 (4) —
 (1) —
 (1) —
 —
 —
 —
Mark-to-market derivative liabilities(c)
—
 —
 —
 —
 (1) —
 —
 (1) —
 —
 —
 —
Effect of netting and allocation of collateral—
 —
 —
 —
 1
 —
 —
 1
 —
 —
 —
 —
Mark-to-market derivative liabilities subtotal—
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (5) —
 (5) —
 (1) —
 (1) —
 —
 —
 —
—
 (4) —
 (4) —
 (1) —
 (1) —
 —
 —
 —
Total net assets (liabilities)$76
 $33
 $19

$128
 $42
 $(1) $—
 $41
 $130
 $—
 $—
 $130
$80
 $31
 $22

$133
 $—
 $(1) $—
 $(1) $29
 $—
 $—
 $29
_________
(a)PHI excludes cash of $18$33 million and $19$12 million at September 30, 20172018 and December 31, 20162017, respectively, and includes long-term restricted cash of $22$19 million and $23 million at September 30, 20172018 and December 31, 20162017, respectively, which is reported in otherOther deferred debits on the balance sheet.Consolidated Balance Sheets.  Pepco excludes cash of $7 million and $9 million at September 30, 2017 and December 31, 2016. DPL excludes cash of $3$12 million and $4 million at September 30, 20172018 and December 31, 2016.2017, respectively. DPL excludes cash of $8 million and $2 million at September 30, 2018 and December 31, 2017, respectively. ACE excludes cash of $5$11 million and $3$2 million at September 30, 20172018 and December 31, 20162017, respectively, and includes long-term restricted cash of $22$19 million and $23 million at September 30, 20172018 and December 31, 20162017, respectively, which is reported in otherOther deferred debits on the balance sheet.Consolidated Balance Sheets.
(b)The amount of unrealized gains/(losses) at PHI totaled less than $1 million for the three months ended September 30, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at Pepco totaled $1 million and less than $1 million for the three months ended September 30, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at PHI totaled $1 million and less than $1 million for the nine months ended September 30, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at Pepco totaled less than $1 million for the nine months ended September 30, 2018 and 2017, respectively.
(c)Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 20172018 and 2016:2017:
                 Generation ComEd PHI   Exelon
            Successor    
Generation ComEd PHI   Exelon
Three Months Ended September 30, 2017
NDT Fund
Investments
 
Pledged Assets
for Zion Station
Decommissioning
 
Mark-to-Market
Derivatives
 
Other
Investments
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation Total
Balance as of June 30, 2017$683
 $21
 $589
 $41
 $1,334
 $(256) $20
 $—
 $1,098
Three Months Ended September 30, 2018
NDT Fund
Investments
 
Pledged Assets
for Zion Station
Decommissioning
 
Mark-to-Market
Derivatives
 
Other
Investments
 Total Generation 
Mark-to-Market
Derivatives
 
Life Insurance Contracts(c)
 Eliminated in Consolidation Total
Balance as of June 30, 2018$585
 $18
 $737
 $36
 $1,376
 $(252) $36
 $—
 $1,160
Total realized / unrealized gains (losses)        
       
        
       
Included in net income—
 —
 (82)
(a) 
1
 (81) —
 1
 —
 (80)(1) —
 (259)
(a) 
13
 (247) —
 1
 —
 (246)
Included in noncurrent payables to affiliates(4) —
 —
 —
 (4) —
 —
 4
 —
Included in payable for Zion Station decommissioning—
 (4) —
 —
 (4) —
 —
 —
 (4)—
 2
 —
 —
 2
 —
 —
 —
 2
Included in regulatory assets—
 —
 —
 —
 —
 (21)
(b) 
—
 —
 (21)
Included in regulatory assets/liabilities—
 —
 —
 —
 —
 (7)
(b) 
—
 (4) (11)
Change in collateral—
 —
 11
 —
 11
 —
 —
 —
 11
—
 —
 (44) —
 (44) —
 —
 —
 (44)
Purchases, sales, issuances and settlements        

       

        
       

Purchases19
 —
 57
 1
 77
 —
 —
 —
 77
15
 —
 81
 3
 99
 —
 —
 —
 99
Sales—
 (20) —
 —
 (20) —
 —
 —
 (20)
Settlements(31) —
 10
(c) 
—
 (21) —
 —
 —
 (21)(29) —
 —
 —
 (29) —
 —
 —
 (29)
Transfers into Level 3—
 —
 3
 —
 3
 —
 —
 —
 3
Transfers out of Level 3—
 —
 10
 —
 10
 —
 —
 —
 10
—
 —
 (6) —
 (6) —
 —
 —
 (6)
Balance at September 30, 2017$671
 $17
 $595
 $43
 $1,326
 $(277) $21
 $—
 $1,070
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2017$—
 $—
 $24
 $1
 $25
 $—
 $1
 $—
 $26
Balance at September 30, 2018$566
 $—
 $512
 $52
 $1,130
 $(259) $37
��$—
 $908
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2018$(1) $—
 $(104) $13
 $(92) $—
 $—
 $—
 $(92)

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

            Successor    Generation ComEd PHI   Exelon
Generation ComEd PHI   Exelon
Nine Months Ended September 30, 2017
NDT Fund
Investments
 
Pledged Assets
for Zion Station
Decommissioning
 
Mark-to-Market
Derivatives
 
Other
Investments
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation��Total
Balance as of December 31, 2016$677
 $19
 $493
 $42
 $1,231
 $(258) $20
 $—
 $993
Nine Months Ended September 30, 2018
NDT Fund
Investments
 
Pledged Assets
for Zion Station
Decommissioning
 
Mark-to-Market
Derivatives
 Other Investments Total Generation 
Mark-to-Market
Derivatives
 
Life Insurance Contracts(c)
 Eliminated in Consolidation Total
Balance as of December 31, 2017$648
 $12
 $552
 $37
 $1,249
 $(256) $22
 $—
 $1,015
Total realized / unrealized gains (losses)        

       

        

       

Included in net income4
 —
 (110)
(a) 
2
 (104) —
 2
 —
 (102)(1) —
 (188)
(a) 
14
 (175) —
 3
 —
 (172)
Included in noncurrent payables to affiliates13
 —
 —
 —
 13
 —
 —
 (13) —
—
 —
 —
 —
 —
 —
 —
 —
 —
Included in payable for Zion Station decommissioning—
 (3) —
 —
 (3) —
 —
 —
 (3)—
 7
 —
 —
 7
 —
 —
 —
 7
Included in regulatory assets—
 —
 —
 —
 —
 (19)
(b) 
—
 13
 (6)—
 —
 —
 —
 —
 (3)
(b) 
—
 —
 (3)
Change in collateral—
 —
 81
 —
 81
 —
 —
 —
 81
—
 —
 14
 —
 14
 —
 —
 —
 14
Purchases, sales, issuances and settlements        

       

        

       

Purchases54
 1
 146
 4
 205
 —
 —
 —
 205
34
 1
 181
 3
 219
 —
 —
 —
 219
Sales—
 —
 (15) —
 (15) —
 —
 —
 (15)—
 (20) (3) —
 (23) —
 —
 —
 (23)
Issuances—
 —
 —
 —
 —
 —
 (1) —
 (1)
Settlements(77) —
 (8)
(c) 
—
 (85) —
 —
 —
 (85)(115) —
 —
 —
 (115) —
 12
 —
 (103)
Transfers into Level 3—
 —
 (9) —
 (9) —
 —
 —
 (9)—
 —
 (21) —
 (21) —
 —
 —
 (21)
Transfers out of Level 3—
 —
 17
 (5) 12
 —
 —
 —
 12
—
 —
 (23) (2) (25) —
 —
 —
 (25)
Balance as of September 30, 2017$671
 $17

$595
 $43
 $1,326
 $(277) $21
 $—
 $1,070
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2017$2
 $—
 $161
 $2
 $165
 $—
 $2
 $—
 $167
Balance as of September 30, 2018$566
 $—

$512
 $52
 $1,130
 $(259) $37
 $—
 $908
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2018$(5) $—
 $159
 $14
 $168
 $—
 $—
 $—
 $168
___________________
(a)Includes a reduction for the reclassification of $155 million and $347 million of realized losses due to the settlement of derivative contracts for the three and nine months ended September 30, 2018, respectively.
(b)Includes $4 million of increases in fair value and an increase for realized losses due to settlements of $3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2018. Includes $9 million of decreases in fair value and an increase for realized losses due to settlements of $12 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2018.
(c)The amounts represented are life insurance contracts at Pepco.

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

 Generation ComEd PHI Exelon
Three Months Ended September 30, 2017
NDT Fund
Investments
 
Pledged Assets
for Zion Station
Decommissioning
 
Mark-to-Market
Derivatives
 
Other
Investments
 Total Generation 
Mark-to-Market
Derivatives
 
Life Insurance Contracts(c)
 Total
Balance as of June 30, 2017$683
 $21
 $589
 $41
 $1,334
 $(256) $20
 $1,098
Total realized / unrealized gains (losses)        

      
Included in net income—
 —
 (82)
(a) 
1
 (81) —
 1
 (80)
Included in noncurrent payables to affiliates—
 —
 —
 —
 —
 —
 —
 —
Included in payable for Zion Station decommissioning—
 (4) —
 —
 (4) —
 —
 (4)
Included in regulatory assets—
 —
 —
 —
 —
 (21)
(b) 
—
 (21)
Change in collateral—
 —
 11
 —
 11
 —
 —
 11
Purchases, sales, issuances and settlements        

      
Purchases19
 —
 57
 1
 77
 —
 —
 77
Sales—
 —
 —
 —
 —
 —
 —
 —
Settlements(31) —
 10
 —
 (21) —
 —
 (21)
Transfers into Level 3—
 —
 —
 —
 —
 —
 —
 —
Transfers out of Level 3—
 —
 10
 —
 10
 —
 —
 10
Balance as of September 30, 2017$671

$17

$595

$43

$1,326

$(277)
$21
 $1,070
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2017$—
 $—
 $24
 $1
 $25
 $—
 $1
 $26

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

 Generation ComEd PHI   Exelon
Nine Months Ended September 30, 2017
NDT Fund
Investments
 
Pledged Assets
for Zion Station
Decommissioning
 
Mark-to-Market
Derivatives
 
Other
Investments
 Total Generation 
Mark-to-Market
Derivatives
 
Life Insurance Contracts(c)
 Eliminated in Consolidation Total
Balance as of December 31, 2016$677
 $19
 $493
 $42
 $1,231
 $(258) $20
 $—
 $993
Total realized / unrealized gains (losses)        

       
Included in net income4
 —
 (110)
(a) 
2
 (104) —
 2
 —
 (102)
Included in noncurrent payables to affiliates13
 —
 —
 —
 13
 —
 —
 (13) —
Included in payable for Zion Station decommissioning—
 (3) —
 —
 (3) —
 —
 —
 (3)
Included in regulatory assets—
 —
 —
 —
 —
 (19)
(b) 
—
 13
 (6)
Change in collateral—
 —
 81
 —
 81
 —
 —
 —
 81
Purchases, sales, issuances and settlements        

       
Purchases54
 1
 146
 4
 205
 —
 —
 —
 205
Sales—
 —
 (15) —
 (15) —
 —
 —
 (15)
Issuances—
 —
 —
 —
 —
 —
 (1) —
 (1)
Settlements(77) 

 (8) 

 (85) —
 —
 —
 (85)
Transfers into Level 3—
 —
 (9) —
 (9) —
 —
 —
 (9)
Transfers out of Level 3—
 —
 17
 (5) 12
 —
 —
 —
 12
Balance as of September 30, 2017$671
 $17
 $595
 $43
 $1,326

$(277) $21
 $—
 $1,070
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2017$2
 $—
 $161
 $2
 $165
 $—
 $2
 $—
 $167
__________
(a)Includes a reduction for the reclassification of $96 million and $279 million of realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2017.2017, respectively.
(b)Includes $24 million of decreasesincreases in fair value and an increase for realized losses due to settlements of $3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2017. Includes $32 million of decreases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2017.
(c)Exelon includes the settlement value for any openThe amounts represented are life insurance contracts that were net settled prior to their scheduled maturity within this line item.at Pepco.

109
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

             Successor    
 Generation ComEd PHI   Exelon
Three Months Ended September 30, 2016
NDT Fund
Investments
 
Pledged Assets
for Zion Station
Decommissioning
 
Mark-to-Market
Derivatives
 
Other
Investments
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation Total
Balance as of June 30, 2016$715
 $25
 $609
 $37
 $1,386
 $(221) $20
 $—
 $1,185
Total realized / unrealized gains (losses)        

        
Included in net income(4) —
 95
(a) 
1
 92
 —
 1
 —
 93
Included in noncurrent payables to affiliates6
 —
 —
 —
 6
 —
 —
 (6) —
Included in payable for Zion Station decommissioning—
 (1) —
 —
 (1) —
 —
 —
 (1)
Included in regulatory assets—
 —
 —
 —
 —
 (23)
(b) 
—
 6
 (17)
Change in collateral—
 —
 31
 —
 31
 —
 —
 —
 31
Purchases, sales, issuances and settlements        

        
Purchases4
 —
 207
(c) 
3
 214
 —
 —
 —
 214
Sales—
 (5) (2) —
 (7) —
 —
 —
 (7)
Issuances—
 —
 —
 —
 —
 —
 —
 —
 —
Settlements(28) —
 —
 —
 (28) —
 —
 —
 (28)
Transfers into Level 3—
 —
 (1) 1
 —
 —
 —
 —
 —
Transfers out of Level 3—
 —
 (4) —
 (4) —
 —
 —
 (4)
Balance as of September 30, 2016$693

$19

$935

$42

$1,689

$(244)
$21
 $—

$1,466
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2016$3
 $—
 $285
 $—
 $288
 $—
 $—
 $—
 $288

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

             Successor    
 Generation ComEd 
PHI(d)
   Exelon
Nine Months Ended September 30, 2016
NDT Fund
Investments
 
Pledged Assets
for Zion Station
Decommissioning
 
Mark-to-Market
Derivatives
 
Other
Investments
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation Total
Balance as of December 31, 2015$670
 $22
 $1,051
 $33
 $1,776
 $(247) $—
 $—
 $1,529
Included due to merger—
 —
 —
 —
 —
 —
 20
 —
 20
Total realized / unrealized gains (losses)        

       
Included in net income2
 —
 (339)
(a) 
1
 (336) —
 2
 —
 (334)
Included in noncurrent payables to affiliates18
 —
 —
 —
 18
 —
 —
 (18) —
Included in payable for Zion Station decommissioning—
 1
 —
 —
 1
 —
 —
 —
 1
Included in regulatory assets—
 —
 —
 —
 —
 3
(b) 
—
 18
 21
Change in collateral—
 —
 (51) —
 (51) —
 —
 —
 (51)
Purchases, sales, issuances and settlements        

       
Purchases123
 1
 289
(c) 
7
 420
 —
 —
 —
 420
Sales(1) (5) (5) —
 (11) —
 —
 —
 (11)
Issuances—
 —
 —
 —
 —
 —
 (1) —
 (1)
Settlements(119) —
 —
 —
 (119) —
 —
 —
 (119)
Transfers into Level 3—
 —
 1
 1
 2
 —
 —
 —
 2
Transfers out of Level 3—
 —
 (11) —
 (11) —
 —
 —
 (11)
Balance as of September 30, 2016$693
 $19
 $935
 $42
 $1,689

$(244) $21
 $—
 $1,466
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2016$7
 $—
 $240
 $—
 $247
 $—
 $1
 $—
 $248
_________
(a)Includes a reduction for the reclassification of $190 million and $579 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2016.
(b)Includes $25 million of decreases in fair value and an increase for realized losses due to settlements of $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2016. Includes $10 million of decreases in fair value and an increase for realized losses due to settlements of $13 million for the nine months ended September 30, 2016.
(c)Includes $168 million of fair value from contracts acquired as a result of portfolio acquisitions.
(d)
Successor period represents activity from March 24, 2016 through September 30, 2016. See tables below for PHI's predecessor periods, as well as activity for Pepco for the three and nine months ended September 30, 2017 and 2016.

  Predecessor
  January 1, 2016 to March 23, 2016
PHI Preferred Stock Life Insurance Contracts
Beginning Balance $18
 $19
Total realized / unrealized gains (losses)    
Included in net income (18) 1
Ending Balance
$—
 $20
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period $—
 $1

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

 Life Insurance Contracts
 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
Pepco2017 2016 2017 2016
Beginning balance$20
 $20
 $20
 $19
Total realized / unrealized gains (losses)       
Included in net income1
 1
 2
 3
Purchases, sales, issuances and settlements       
Issuances—
 —
 (1) (1)
Ending balance$21

$21
 $21

$21
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period$1
 $—
 $2
 $2
The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 20172018 and 2016:2017:
       Successor      
 Generation PHI Exelon
 Operating
Revenues		 Purchased
Power and
Fuel		 
Other, net(a)
 
Other, net(a)
 Operating
Revenues		 Purchased
Power and
Fuel		 
Other, net(a)
Total gains (losses) included in net income for the three months ended September 30, 2017$(3) $(69) $1
 $1
 $(3) $(69) $2
Total gains (losses) included in net income for the nine months ended September 30, 201734
 (152) 6
 2
 34
 (152) 8
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 201747
 (23) 1
 1
 47
 (23) 2
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2017222
 (61) 4
 2
 222
 (61) 6
 Generation PHI Exelon
 Operating
Revenues		 Purchased
Power and
Fuel		 Other, net Operating and Maintenance Operating
Revenues		 Purchased
Power and
Fuel		 Operating and Maintenance Other, net
Total gains (losses) included in net income for the three months ended September 30, 2018$(176) $(83) $12
 $1
 $(176) $(83) $1
 $12
Total gains (losses) included in net income for the nine months ended September 30, 2018(32) (156) 13
 3
 (32) (156) 3
 13
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2018(64) (40) 12
 —
 (64) (40) —
 12
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2018174
 (15) 9
 —
 174
 (15) —
 9
       Successor      
 Generation PHI Exelon
 
Operating
Revenues
 
Purchased
Power and
Fuel
 
Other, net(a)
 
Other, net(a)
 
Operating
Revenues
 
Purchased
Power and
Fuel
 
Other, net(a)
Total gains (losses) included in net income for the three months ended September 30, 2016$180
 $(85) $(4) $1
 $180
 $(85) $(3)
Total gains (losses) included in net income for the nine months ended September 30, 2016(232) (107) 2
 2
 (232) (107) 4
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2016323
 (38) 3
 —
 323
 (38) 3
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2016303
 (63) 7
 1
 303
 (63) 8
 Generation PHI Exelon
 
Operating
Revenues
 
Purchased
Power and
Fuel
 Other, net 
Other, net(a)
 
Operating
Revenues
 
Purchased
Power and
Fuel
 Other, net
Total gains (losses) included in net income for the three months ended September 30, 2017$(3) $(69) $1
 $1
 $(3) $(69) $2
Total gains (losses) included in net income for the nine months ended September 30, 201734
 (152) 6
 2
 34
 (152) 8
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 201747
 (23) 1
 1
 47
 (23) 2
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2017222
 (61) 4
 2
 222
 (61) 6

112
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

 Predecessor        
 PHI Pepco
 January 1, 2016 to March 23, 2016 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
  2017 2016 2017 2016
 
Other, net(a)

 
Other, net(a)

Total gains (losses) included in net income$(17) $1
 $1
 $2
 $3
Change in the unrealized gains (losses) relating to assets and liabilities held1
 1
 —
 2
 2
_________
(a)Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation, accrued interest on a convertible promissory note at Generation and the life insurance contracts held by PHI and 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)(All Registrants).The Registrants’ cash equivalents include investments with original maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.
Preferred Stock Derivative (PHI). In connection with entering into the PHI Merger Agreement, 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 and Fixed Income. Generation’s and CENG's NDT fund investments policies

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

outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.
With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds which are based on quoted prices in active markets are categorized in Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.
For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the 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

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

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 partythird-party valuation that contains significant unobservable inputs and are categorized in Level 3.
Equity and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives such as holding short-term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For commingled funds and mutual funds, which are not publicly quoted, the funds are valued using NAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the underlying securities, and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.
Derivative instruments consisting primarily of futures and interest rate swaps to manage risk are recorded at fair value. Over the counter derivatives are valued daily based on quoted prices in active markets and trade in open markets and have been categorized as Level 1. Derivative instruments other than over the counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.
Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models and income models. Investments in loans are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Managed funds are valued using NAV or its

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

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 unobservable.
As of September 30, 2017,2018, Generation has outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $75$135 million,, $285 $208 million,$240 $349 million, and$95 $227 million, respectively. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.
Concentrations of Credit RiskRisk.. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of September 30, 2017.2018. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of September 30, 2017,2018, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.
See Note 13 — Nuclear DecommissioningAsset Retirement Obligations for further discussionadditional information on the NDT fund investments.
Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE)Pepco).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

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

life insurance policies. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3.
Mark-to-Market Derivatives (Exelon, Generation, ComEd, PHI and DPL)..Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between

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

market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.
Exelon may utilize fixed-to-floating interest rate swaps 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 10 -— Derivative Financial Instruments for further discussionadditional information on mark-to-market derivatives.
Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)(All Registrants).The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.
The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.
Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd, PHI, Pepco, DPL and ACE)
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.

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, and Pepco). 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.
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

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

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

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

typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.93$3.38 and $0.41$0.46 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 10 —Derivative Financial Instruments for moreadditional 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.
116
Type of trade Fair Value at September 30, 2018 
Valuation
Technique
 
Unobservable
Input
 Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)
 $359
 Discounted
Cash Flow		 Forward power
price		 $9-$158
  

 
 Forward gas
price		 $1.10-$12.57
  

 Option Model Volatility
percentage		 8%-211%
           
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
 $58
 Discounted
Cash Flow		 Forward power
price		 $17-$158
           
Mark-to-market derivatives (Exelon and ComEd) $(259) Discounted
Cash Flow		 
Forward heat
rate(c)
 10x-11x
      Marketability
reserve		 4%-8%
      Renewable
factor		 86%-121%
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

The table below discloses the significant inputs to the forward curve used to value these positions.
Type of trade Fair Value at September 30, 2017 
Valuation
Technique
 
Unobservable
Input
 Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)
 $439
 Discounted
Cash Flow		 Forward power
price		 $7-$124
  

 
 Forward gas
price		 $1.84-$9.43
  

 Option Model Volatility
percentage		 9%-114%
           
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
 $15
 Discounted
Cash Flow		 Forward power
price		 $12-$69
           
Mark-to-market derivatives (Exelon and ComEd) $(277) Discounted
Cash Flow		 
Forward heat
rate(c)
 9x-10x
      Marketability
reserve		 3%-8%
      Renewable
factor		 88%-125%
_________
(a)The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
(b)The fair values do not include cash collateral posted on level three positions of $141 million as of September 30, 2017.
(c)Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
Type of trade Fair Value at December 31, 2016 
Valuation
Technique
 
Unobservable
Input
 Range Fair Value at December 31, 2017 
Valuation
Technique
 
Unobservable
Input
 Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)
 $435
 Discounted
Cash Flow		 Forward power price $11-$130 $445
 Discounted
Cash Flow		 Forward power price $3-$124
 

 
 Forward gas price $1.72-$9.20 

 
 Forward gas price $1.27-$12.80
 

 Option Model Volatility percentage 8%-173% 

 Option Model Volatility percentage 11%-139%
      
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
 $(3) Discounted
Cash Flow		 Forward power price $19-$79 $26
 Discounted
Cash Flow		 Forward power price $14-$94
      
Mark-to-market derivatives (Exelon and ComEd) $(258) Discounted Cash Flow 
Forward heat
rate(c)
 8x-9x $(256) Discounted Cash Flow 
Forward heat
rate(c)
 9x-10x
   Marketability reserve 3%-8%   Marketability reserve 4%-8%
   Renewable factor 89%-121%   Renewable factor 88%-120%
_________
(a)The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
(b)The fair values do not include cash collateral posted on level three positions of $61$94 million and $81 million as of September 30, 2018 and December 31, 2016.2017, respectively.
(c)Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
The inputs listed above 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

117
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

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 StationDecommissioning (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.
Rabbi Trust Investments - Life insurance contracts (Exelon, PHI, Pepco, DPL and ACE). Forlife 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.
10. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, foreign currency exchangeinterest rate risk and interest rateforeign exchange risk related to ongoing business operations.
Commodity Price Risk (All Registrants)
To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and energy-relatedcommodity products. The Registrants believe these

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

instruments, which are either determined to be non-derivative or classified as either economic hedges, or non-derivatives, mitigate exposure to fluctuations in commodity prices.
Derivative accountingauthoritative 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.immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedge,hedges and fair value hedge.hedges. For Generation, all derivative economic hedges related to commodities are recorded at fair value through earnings for the consolidated company, referred to as economic hedges in the following tables. 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 exposedFair value authoritative guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to commodity price risk primarily relating to changesbe shown in the market priceCombined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of electricity, fossil fuels,all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column. As of September 30, 2018, $23 million of cash collateral posted, and as of December 31, 2017, $4 million of cash collateral held, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or had no positions to offset as of the balance sheet date. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other commodities associatednon-derivative contracts that are accounted for under the accrual method of accounting.
ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1).
Cash collateral held by PECO and BGE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with price movements resulting from changesa U.S. branch office that meet certain qualifications.
In the table below, DPL's economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column.

118
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 September 30, 2018:
  Generation ComEd DPL Exelon
Derivatives 
Economic
Hedges
 
Proprietary
Trading
 
Collateral
and
Netting(a)(e)
 
Subtotal(b)
 
Economic
Hedges(c)
 
Economic
Hedges(d)
 
Collateral
and
Netting(a)
 Subtotal 
Total
Derivatives
Mark-to-market derivative assets (current assets) $2,987
 $113
 $(2,406) $694
 $—
 $—
 $—
 $—
 $694
Mark-to-market derivative assets (noncurrent assets) 1,383
 61
 (1,013) 431
 —
 —
 —
 —
 431
Total mark-to-market derivative assets 4,370
 174
 (3,419) 1,125
 —
 —
 —
 —
 1,125
Mark-to-market derivative liabilities (current liabilities) (2,761) (86) 2,543
 (304) (24) —
 —
 —
 (328)
Mark-to-market derivative liabilities (noncurrent liabilities) (1,284) (41) 1,088
 (237) (235) —
 —
 —
 (472)
Total mark-to-market derivative liabilities (4,045) (127) 3,631
 (541) (259) —
 —
 —
 (800)
Total mark-to-market derivative net assets (liabilities) $325
 $47
 $212
 $584
 $(259) $—
 $—
 $—
 $325
_________
(a)Exelon, Generation and DPL net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
(b)Current and noncurrent assets are shown net of collateral of $71 million and $28 million, respectively, and current and noncurrent liabilities are shown net of collateral of $66 million and $47 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $212 million at September 30, 2018.
(c)Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(d)Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
(e)Of the collateral posted/(received), $(166) million represents variation margin on the exchanges.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. 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, 2017:
  Generation ComEd DPL Exelon
Description Economic
Hedges		 Proprietary
Trading		 
Collateral
and
Netting(a)(e)
 
Subtotal(b)
 
Economic
Hedges(c)
 
Economic
Hedges(d)
 
Collateral and
Netting(a)
 Subtotal Total
Derivatives
Mark-to-market derivative assets (current assets) $3,061
 $56
 $(2,144) $973
 $—
 $—
 $—
 $—
 $973
Mark-to-market derivative assets (noncurrent assets) 1,164
 12
 (845) 331
 —
 —
 —
 —
 331
Total mark-to-market derivative assets 4,225
 68
 (2,989) 1,304
 —
 —
 —
 —
 1,304
Mark-to-market derivative liabilities (current liabilities) (2,646) (43) 2,480
 (209) (21) (1) 1
 —
 (230)
Mark-to-market derivative liabilities (noncurrent liabilities) (1,137) (10) 975
 (172) (235) —
 —
 —
 (407)
Total mark-to-market derivative liabilities (3,783) (53) 3,455
 (381) (256) (1) 1
 —
 (637)
Total mark-to-market derivative net assets (liabilities) $442
 $15
 $466
 $923
 $(256) $(1) $1
 $—
 $667
_________ 
(a)Exelon, Generation and DPL net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
(b)Current and noncurrent assets are shown net of collateral of $169 million and $53 million, respectively, and current and noncurrent liabilities are shown net of collateral of $167 million and $77 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $466 million at December 31, 2017.
(c)Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(d)Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
(e)Of the collateral posted/(received), $(117) million represents variation margin on the exchanges.

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

Economic Hedges (Commodity Price Risk)
Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and energypower purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. In order toTo manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecastedexpected sales of energypower and gas and purchases of fuelpower and energy.fuel. The objectives for entering intoexecuting 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.return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis. For the three and nine months ended September 30, 2018 and 2017, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the "Net fair value changes related to derivatives" on the Consolidated Statements of Cash Flows.
  Three Months Ended
September 30,		 Nine Months Ended
September 30,
  2018 2017 2018 2017
Income Statement Location Gain (Loss)
Operating revenues $8
 $55
 $(99) $(41)
Purchased power and fuel 66
 21
 (4) (114)
Total Exelon and Generation $74
 $76
 $(103) $(155)
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 September 30, 2017,2018, the percentage of expected generation hedged is 98%-101%, 79%-82%,82%-85% and 45%-48%48%-51% for 2017, 2018, 2019 and 2019,2020, 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, BGE, Pepco, DPL, and ACE to serve their retail load.
On December 17, 2010, ComEd entered intoexecuted 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 of the Exelon 20162017 Form 10-K 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 5 — 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 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 20162018 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-termlong-

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

term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 20162018 and previous PGC settlement,settlements, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 20% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations and financial position as natural gas costs are fully recovered from customers under the PGC.

119
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE's wholesale power supply costs and include an administrative fee. BGE’s commodity price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.
BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. 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 commodity 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 for all of its SOS requirements through full requirements contracts. DPL’s commodity price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.
DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up versus the forecastagainst forecasts 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

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

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%)50% of estimated purchase requirements for each month, including estimated monthly purchases for storage injections. The fifty percent (50%)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,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

120
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s commodity price risk related to electric supply procurement is limited. ACE locks in fixed prices for 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.Trading (Commodity Price Risk)
Generation also enters into certain energy-relatedexecutes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered intoexecuted with the intent of benefiting from shifts or changes in market prices as opposed to those entered intoexecuted 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 volumesportfolio is subject to a risk management policy that includes stringent risk management limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon's RMC monitor the financial risks of 2,601 GWhs and 6,763 GWhs for the three and nine months ended September 30, 2017, respectively, and 1,506 GWhs and 4,015 GWhs and for the three and nine months September 30, 2016, respectively,proprietary trading activities. The proprietary trading activities are a complement to Generation’sGeneration's energy marketing portfolio but represent a small portion of Generation’sGeneration's overall revenue from energy marketing activities. ComEd, PECO, BGE, PHI, Pepco, DPLGains and ACElosses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. For the three and nine months ended September 30, 2018 and 2017 Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also included in the "Net fair value changes related to derivatives" on the Consolidated Statements of Cash Flows. The Utility Registrants do not enter intoexecute derivatives for proprietary trading purposes.
  Three Months Ended
September 30,		 Nine Months Ended
September 30,
  2018 2017 2018 2017
Income Statement Location Gain (Loss)
Operating revenues $(3) $5
 $14
 $4
Interest Rate and Foreign Exchange Risk (All Registrants)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants also utilize fixed-to-floating interest rate swaps, which are typically designatedtreated as fair valueeconomic 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 September 30, 2017, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding, and Exelon and Generation had $491 million of notional amounts of floating-to-fixed hedges outstanding. To manage foreign exchange rate exposure associated with

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

international energycommodity purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designatedtreated as economic hedges. Below is a summary of the interest rate and foreign exchange hedge balances as of September 30, 2017:2018:
 Generation Exelon Corporate Exelon Generation Exelon Corporate Exelon
Description 
Derivatives
Designated
as Hedging
Instruments
 
Economic
Hedges
 
Proprietary
Trading(a)
 
Collateral
and
Netting(b)
 Subtotal 
Derivatives
Designated
as Hedging
Instruments
 Total 
Economic
Hedges
 
Collateral
and
Netting(a)
 Subtotal Economic Hedges Total
Mark-to-market derivative assets (current assets) $—
 $15
 $—
 $(10) $5
 $—
 $5
 $3
 $(1) $2
 $—
 $2
Mark-to-market derivative assets (noncurrent assets) —
 1
 —
 (1) —
 10
 10
 18
 —
 18
 —
 18
Total mark-to-market derivative assets —
 16
 —
 (11) 5
 10
 15
 21
 (1) 20
 —
 20
Mark-to-market derivative liabilities (current liabilities) —
 (17) —
 9
 (8) —
 (8) (2) 1
 (1) —
 (1)
Mark-to-market derivative liabilities (noncurrent liabilities) —
 (2) —
 1
 (1) —
 (1) —
 —
 —
 (10) (10)
Total mark-to-market derivative liabilities —
 (19) —
 10
 (9) —
 (9) (2) 1
 (1) (10) (11)
Total mark-to-market derivative net assets (liabilities) $—
 $(3) $—
 $(1) $(4) $10
 $6
 $19
 $—
 $19
 $(10) $9
__________
(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 accountingauthoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. Thesecollateral, which are not reflected in the table above.

121
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, 2016:2017:
 Generation Exelon Corporate Exelon Generation Exelon Corporate Exelon
Description 
Derivatives
Designated
as Hedging
Instruments
 
Economic
Hedges
 
Proprietary
Trading(a)
 
Collateral
and
Netting(b)
 Subtotal 
Derivatives
Designated
as Hedging
Instruments
 Total 
Derivatives
Designated
as Hedging
Instruments
 
Economic
Hedges
 
Collateral
and
Netting(a)
 Subtotal 
Derivatives
Designated
as Hedging
Instruments
 Total
Mark-to-market derivative assets (current assets) $—
 $17
 $4
 $(13) $8
 $—
 $8
 $—
 $10
 $(7) $3
 $—
 $3
Mark-to-market derivative assets (noncurrent assets) —
 11
 1
 (8) 4
 16
 20
 3
 —
 —
 3
 3
 6
Total mark-to-market derivative assets —
 28
 5
 (21) 12
 16
 28
 3
 10
 (7) 6
 3
 9
Mark-to-market derivative liabilities (current liabilities) (7) (13) (2) 14
 (8) —
 (8) (2) (7) 7
 (2) —
 (2)
Mark-to-market derivative liabilities (noncurrent liabilities) (3) (8) (2) 9
 (4) —
 (4) —
 (2) —
 (2) —
 (2)
Total mark-to-market derivative liabilities (10) (21) (4) 23
 (12) —
 (12) (2) (9) 7
 (4) —
 (4)
Total mark-to-market derivative net assets (liabilities) $(10) $7
 $1
 $2
 $—
 $16
 $16
Total mark-to-market derivative net assets $1
 $1
 $—
 $2
 $3
 $5
__________
(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 accountingauthoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. Thesecollateral, which are not reflected in the table above.

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

Economic Hedges (Interest Rate and Foreign Exchange Risk)
Exelon and Generation execute these instruments to mitigate exposure to fluctuations in interest rates or foreign exchange but for which the fair value or cash flow hedge elections were not made. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The amount deferred in AOCI associated with the previously designated cash flow hedges will be reclassified into earnings as the underlying forecasted transaction occurs. The result of this de-designation is that all economic hedges for interest rate swaps will be recorded at fair value through earnings going forward, referred to as economic hedges in the following tables.
The following table provides notional amounts outstanding held by Exelon and Generation at September 30, 2018 related to interest rate swaps and foreign currency exchange rate swaps.
  Generation Exelon Corporate Exelon
Foreign currency exchange rate swaps $88
 $—
 $88
Interest rate swaps 625
 800
 1,425
Total $713
 $800
 $1,513
The following table provides notional amounts outstanding held by Exelon and Generation at December 31, 2017 related to interest rate swaps and foreign currency exchange rate swaps.
  Generation Exelon Corporate Exelon
Foreign currency exchange rate swaps $94
 $—
 $94
Interest rate swaps(a)
 1
 —
 1
Total $95
 $—
 $95
__________
(a)On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. The table excludes amounts of $800 million of fixed-to-floating hedges that were previously designated as fair value hedges by Exelon and $636 million of floating-to-fixed hedges that were previously designated as cash flow hedges by Exelon and Generation as of December 31, 2017.
For the three and nine months ended September 30, 2018 and 2017, Exelon and Generation recognized the following net pre-tax mark-to-market gains (losses) in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows.
   Three Months Ended
September 30,		 Nine Months Ended
September 30,
   2018 2017 2018 2017
 Income Statement Location Gain (Loss)
GenerationOperating Revenues $(2) $(3) $3
 $(6)
GenerationPurchased Power and Fuel (1) —
 (4) —
GenerationInterest Expense 4
 —
 4
 —
Total Generation  $1
 $(3) $3
 $(6)

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

   Three Months Ended
September 30,		 Nine Months Ended
September 30,
   2018 2017 2018 2017
 Income Statement Location Gain (Loss)
ExelonOperating Revenues $(2) $(3) $3
 $(6)
ExelonPurchased Power and Fuel (1) —
 (4) —
ExelonInterest Expense 2
 —
 2
 —
Total Exelon  $(1) $(3) $1
 $(6)
Fair Value Hedges.     (Interest Rate Risk)
For derivative instruments that qualify and 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.earnings immediately. Exelon includeshad no fixed-to-floating swaps designated as fair value hedges as of September 30, 2018 and had $800 million notional amounts designated as fair value hedges as of December 31, 2017. Exelon and Generation include the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:
  Three Months Ended September 30, Three Months Ended September 30,
Income Statement
Location
 2017 2016 2017 2016
Income Statement
Location
 2018 2017 2018 2017
 Gain (loss) on Swaps Gain (loss) on Borrowings Loss on Swaps Gain on Borrowings
ExelonInterest expense $(2) $(8) $6
 $14
Interest expense $—
 $(2) $—
 $6
                
  Nine Months Ended September 30, Nine Months Ended September 30,
Income Statement
Location
 2017 2016 2017 2016
Income Statement
Location
 2018 2017 2018 2017
 Gain (loss) on Swaps Gain (loss) on Borrowings Loss on Swaps Gain on Borrowings
ExelonInterest expense $(6) $15
 $17
 $(3)Interest expense $(11) $(6) $20
 $17
At September 30, 2017, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $10 million. 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. During the three and nine months ended September 30, 2018, due to the de-designation of fair value hedges, there was no impact on the results of operations as a result of ineffectiveness from fair value hedges. During the three months ended September 30, 2017, and 2016, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $4 million gain, a $11 million gain, a $6 million gain, and a $12 million gain, respectively.
Cash Flow Hedges.gain. 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

122
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

of Operations and Comprehensive Income over the term of the debt. See Note 11— 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 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 its long-term borrowings. The swaps were de-designated as cash flow hedges and, during the second quarter of 2017, upon termination of the debt, Generation terminated the swaps. The total notional amount of the swaps was $164 million. No gain or loss was recognized as a result of the termination of the swaps. See Note 11 — Debt and Credit Agreements for additional information.
During the three and nine months ended September 30, 20172018 and 2016,2017, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $9 million gain and a $11 million gain, respectively.
Cash Flow Hedges (Interest Rate Risk)
For derivative instruments that qualify and are designated as cash flow hedges, in continuing designated hedge relationships was immaterial.
Economic Hedges.  During the third quarter of 2014, EGTP, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage again or loss on the effective portion of its interest rate exposurethe derivative will be deferred in connection withAOCI and reclassified into earnings when the long-term borrowing. See Note 14 —Debtunderlying transaction occurs. Exelon and Credit Agreements of the Exelon 2016 Form 10-K for additional information regarding the financing. TheGeneration have no floating-to-fixed swaps have a notional amount of $491 milliondesignated as cash flow hedges as of September 30, 20172018, and expire in 2019. The swap washad $636 million notional amounts designated as a cash flow hedge in the fourth quarterhedges as of 2014. During the first quarter of 2017, the swap was de-designated. At September 30, 2017, the subsidiary had a $6 million derivative liability related to the swap. During the three and nine months ended September 30, 2017, a gain of $2 million and a loss of $2 million related to the swap, respectively, were recorded to Interest expense.
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 of the Exelon 2016 Form 10-K 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 was $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 of the Exelon 2016 Form 10-K 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.
At September 30, 2017, Generation had immaterial notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $111 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 netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, Generation’s energy related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column. As of September 30, 2017 and December 31, 2016, $32017.

123
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

million and $8 million of cash collateral held, 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, including margin on exchange positions, is aggregated in the collateral and netting column.
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of September 30, 2017:
                  Successor  
  Generation ComEd DPL PHI Exelon
Derivatives 
Economic
Hedges
 
Proprietary
Trading
 
Collateral
and
Netting(a) (e)
 
Subtotal(b)
 
Economic
Hedges(c)
 
Economic
Hedges(d)
 
Collateral
and
Netting(a)
 Subtotal Subtotal 
Total
Derivatives
Mark-to-market derivative assets (current assets) $2,608
 $55
 $(1,969) $694
 $—
 $—
 $—
 $—
 $—
 $694
Mark-to-market derivative assets (noncurrent assets) 1,583
 30
 (1,197) 416
 —
 —
 —
 —
 —
 416
Total mark-to-market derivative assets 4,191

85
 (3,166) 1,110
 —
 —
 —
 —

—
 1,110
Mark-to-market derivative liabilities (current liabilities) (2,334) (46) 2,230
 (150) (20) —
 —
 —
 —
 (170)
Mark-to-market derivative liabilities (noncurrent liabilities) (1,476) (27) 1,351
 (152) (257) —
 —
 —
 —
 (409)
Total mark-to-market derivative liabilities (3,810) (73) 3,581
 (302) (277) —
 —
 —

—
 (579)
Total mark-to-market derivative net assets (liabilities) $381
 $12
 $415
 $808
 $(277) $—
 $—
 $—

$—
 $531
_________
(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 $123 million and $61 million, respectively, and current and noncurrent liabilities are shown net of collateral of $138 million and $93 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $415 million at September 30, 2017.
(c)Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(d)Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
(e)Of the collateral posted/(received), $27 million represents variation margin on the exchanges.

124
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:
                  Successor  
  Generation ComEd DPL PHI Exelon
Description 
Economic
Hedges
 
Proprietary
Trading
 
Collateral
and
Netting(a) (e)
 
Subtotal(b)
 
Economic
Hedges(c)
 
Economic
Hedges(d)
 
Collateral and
Netting(a)
 Subtotal Subtotal Total
Derivatives
Mark-to-market derivative assets (current assets) $3,623
 $55
 $(2,769) $909
 $—
 $2
 $(2) $—
 $—
 $909
Mark-to-market derivative assets (noncurrent assets) 1,467
 21
 (1,016) 472
 —
 —
 —
 —
 —
 472
Total mark-to-market derivative assets 5,090
 76
 (3,785) 1,381
 —
 2
 (2) —
 —
 1,381
Mark-to-market derivative liabilities (current liabilities) (3,165) (54) 2,964
 (255) (19) —
 —
 —
 —
 (274)
Mark-to-market derivative liabilities (noncurrent liabilities) (1,274) (25) 1,150
 (149) (239) —
 —
 —
 —
 (388)
Total mark-to-market derivative liabilities (4,439) (79) 4,114
 (404) (258) —
 —
 —
 —
 (662)
Total mark-to-market derivative net 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, 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 $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.
(c)Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(d)Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
(e)Of the collateral posted/(received), $(158) million represents variation margin on the exchanges.

125
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 three and nine months ended September 30, 20172018 and 2016,2017, containing information about the changes in the fair value of cash flow hedges and the reclassification from Accumulated OCIAOCI 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.
 Total Cash Flow Hedge OCI Activity, Net of Income Tax                   
Generation Exelon 
Three Months Ended September 30, 2017 
Income Statement
Location
 Total Cash 
Flow Hedges		 
Total Cash 
Flow Hedges
 
Accumulated OCI derivative loss at June 30, 2017   $(14) $(12) 
Effective portion of changes in fair value   1
 1
 
Reclassifications from AOCI to net income Interest Expense (1)
(a)  
(1)
(a)  
Accumulated OCI derivative loss at September 30, 2017   $(14) $(12) 
 Total Cash Flow Hedge OCI Activity, Net of Income Tax                   
Generation Exelon 
Nine Months Ended September 30, 2017 
Income Statement
Location
 Total Cash 
Flow Hedges		 Total Cash 
Flow Hedges		 
Accumulated OCI derivative loss at December 31, 2016   $(19) $(17) 
Effective portion of changes in fair value   2
  
2
 
Reclassifications from AOCI to net income Interest Expense 3
(b)  
3
(b)  
Accumulated OCI derivative loss at September 30, 2017   $(14) $(12) 
  Total Cash Flow Hedge OCI Activity, Net of Income Tax                   
 Generation Exelon 
Three Months Ended September 30, 2016 
Income Statement
Location
 Total Cash 
Flow Hedges		 
Total Cash 
Flow Hedges
 
Accumulated OCI derivative loss at June 30, 2016   $(25) $(26) 
Effective portion of changes in fair value   1
  
3
 
Accumulated OCI derivative loss at September 30, 2016   $(24) $(23) 
  Total Cash Flow Hedge OCI Activity, Net of Income Tax                   
 Generation Exelon 
Nine Months Ended September 30, 2016 
Income Statement
Location
 Total Cash 
Flow Hedges		 
Total Cash
Flow Hedges
 
Accumulated OCI derivative loss at December 31, 2015   $(21) $(19) 
Effective portion of changes in fair value   —
  
(1) 
Reclassifications from AOCI to net income Interest Expense (3)
(c) 
(3)
(c) 
Accumulated OCI derivative loss at September 30, 2016   $(24) $(23) 
 Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon 
Three Months Ended September 30, 2018 
Income Statement
Location
 Total Cash 
Flow Hedges		 
Total Cash 
Flow Hedges
 
AOCI derivative loss at June 30, 2018   $(4) $(2) 
Reclassifications from AOCI to net income Interest Expense —
 —
 
AOCI derivative loss at September 30, 2018   $(4) $(2) 
        
 Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon 
Nine Months Ended September 30, 2018 
Income Statement
Location
 Total Cash 
Flow Hedges		 Total Cash 
Flow Hedges		 
AOCI derivative loss at December 31, 2017   $(16) $(14) 
Effective portion of changes in fair value   11
 11
 
Reclassifications from AOCI to net income Interest Expense 1
 1
 
AOCI derivative loss at September 30, 2018   $(4) $(2) 
        
  Total Cash Flow Hedge OCI Activity, Net of Income Tax
 Generation Exelon 
Three Months Ended September 30, 2017 
Income Statement
Location
 Total Cash 
Flow Hedges		 
Total Cash 
Flow Hedges
 
AOCI derivative loss at June 30, 2017   $(14) $(12) 
Effective portion of changes in fair value   1
 1
 
Reclassifications from AOCI to net income Interest Expense (1)
(a) 
(1)
(a) 
AOCI derivative loss at September 30, 2017   $(14) $(12) 
        
  Total Cash Flow Hedge OCI Activity, Net of Income Tax
 Generation Exelon 
Nine Months Ended September 30, 2017 
Income Statement
Location
 Total Cash 
Flow Hedges		 
Total Cash
Flow Hedges
 
AOCI derivative loss at December 31, 2016   $(19) $(17) 
Effective portion of changes in fair value   2
 2
 
Reclassifications from AOCI to net income Interest Expense 3
(b) 
3
(b) 
AOCI derivative loss at September 30, 2017   $(14) $(12) 
_________
(a)Amount is net of related income tax benefit of $1 million for the three months ended September 30, 2017.
(b)Amount is net of related income tax expense of $2 million for the nine months ended September 30, 2017.
(c)Amount is net of related income tax expense of $2 million for the nine months ended September 30, 2016.
During the three months ended September 30, 2018, due to the de-designation of cash flow hedges, there was no impact on the results of operations as a result of ineffectiveness. During the nine months

126
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Economic Hedges (Exelonended September 30, 2018 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 three and nine months ended September 30, 2017, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial. The estimated amount of existing gains and 2016, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts werelosses that are reported in Operating 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 heldAOCI at the reporting date. The “Reclassificationdate that are expected to realized” generally representsbe reclassified into earnings within the recognized change in fair value that was reclassified from unrealized to realized when the transaction to which the derivative relates occurs.next twelve months is immaterial.
  Generation Exelon
Three Months Ended September 30, 2017 
Operating
Revenues
 
Purchased
Power 
and Fuel
 Total Total
Change in fair value of commodity positions $132
 $45
 $177
 $177
Reclassification to realized at settlement of commodity positions (77) (24) (101) (101)
Net commodity mark-to-market gains (losses) 55
 21
 76
 76
Change in fair value of treasury positions (3) —
 (3) (3)
Reclassification to realized at settlement of treasury positions —
 —
 —
 —
Net treasury mark-to-market gains (losses) (3) —
 (3) (3)
      Net mark-to-market gains (losses) $52
 $21
 $73
 $73
  Generation Exelon
Nine Months Ended September 30, 2017 
Operating
Revenues
 
Purchased
Power 
and Fuel
 Total Total
Change in fair value of commodity positions $123
 $(153) $(30) $(30)
Reclassification to realized of commodity positions (164) 39
 (125) (125)
Net commodity mark-to-market gains (losses) (41) (114) (155) (155)
Change in fair value of treasury positions (4) —
 (4) (4)
Reclassification to realized of treasury positions (2) —
 (2) (2)
Net treasury mark-to-market gains (losses) (6) —
 (6) (6)
     Net mark-to-market gains (losses) $(47) $(114) $(161) $(161)
  Generation Exelon
Three Months Ended September 30, 2016 
Operating
Revenues
 
Purchased
Power
and Fuel
 Total Total
Change in fair value of commodity positions $280
 $(73) $207
 $207
Reclassification to realized at settlement of commodity positions (92) (26) (118) (118)
Net commodity mark-to-market gains (losses) 188
 (99) 89
 89
Change in fair value of treasury positions 1
 —
 1
 1
Reclassification to realized at settlement of treasury positions (2) —
 (2) (2)
Net treasury mark-to-market gains (losses) (1) —
 (1) (1)
     Net mark-to-market gains (losses) $187
 $(99) $88
 $88

127
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

  Generation Exelon
Nine Months Ended September 30, 2016 
Operating
Revenues
 
Purchased
Power
and Fuel
 Total Total
Change in fair value of commodity positions $127
 $36
 $163
 $163
Reclassification to realized of commodity positions (484) 217
 (267) (267)
Net commodity mark-to-market gains (losses) (357) 253
 (104) (104)
Change in fair value of treasury positions (3) —
 (3) (3)
Reclassification to realized of treasury positions (6) —
 (6) (6)
Net treasury mark-to-market gains (losses) (9) —
 (9) (9)
      Net mark-to-market gains (losses) $(366) $253
 $(113) $(113)
Proprietary Trading Activities (Exelon(Interest Rate and Generation).    For the three and nine months ended September 30, 2017 and 2016, Exelon and Foreign Exchange Risk)
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 commodityalso executes derivative instruments entered intocontracts 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 operatingOperating 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. InFor the tables below, “Change in fair value” representsthree and nine months ended September 30, 2018 and for the change in fair value ofthree months ended September 30, 2017, Exelon and Generation recognized no net pre-tax commodity mark-to-market gains or losses. For the derivative contracts held at the reporting date. The “Reclassification to realized” represents thenine months ended September 30, 2017, Exelon and Generation recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.
   Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
   2017 2016 2017 2016
Change in fair value of commodity positions $11
 $4
 $17
 $18
Reclassification to realized of commodity positions (6) (6) (13) (17)
Net commodity mark-to-market gains (losses) 5
 (2) 4
 1
Change in fair value of treasury positions (1) —
 (2) (2)
Reclassification to realized of treasury positions 1
 1
 1
 2
Net treasury mark-to-market gains (losses) —
 1
 (1) —
Total net mark-to-market gains (losses) $5
 $(1) $3
 $1
a $1 million net pre-tax commodity mark-to-market loss.
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 intoon executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments,commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

128
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 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 September 30, 2017.2018. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, Nuclearnuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $18$47 million, $22$26 million,, $22 $23 million, $34$39 million, $12$8 million, and $7$6 million as of September 30, 2017,2018, respectively. 
Rating as of September 30, 2017Total Exposure Before Credit Collateral 
Credit Collateral(a)
 Net Exposure Number of Counterparties Greater than 10% of Net Exposure Net Exposure of Counterparties Greater than 10% of Net Exposure
Rating as of September 30, 2018Total Exposure Before Credit Collateral 
Credit Collateral(a)
 Net Exposure Number of Counterparties Greater than 10% of Net Exposure Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade$828
 $9
 $819
 1
 $278
$647
 $—
 $647
 1
 $176
Non-investment grade44
 4
 40
 

 

101
 20
 81
 

 

No external ratings                  
Internally rated — investment grade316
 —
 316
 

 

179
 1
 178
 

 

Internally rated — non-investment grade100
 18
 82
 

 

139
 17
 122
 

 

Total$1,288
 $31
 $1,257
 1
 $278
$1,066
 $38
 $1,028
 1
 $176
 
Net Credit Exposure by Type of CounterpartyAs of
September 30, 2017		 As of
September 30, 2018
Financial institutions$48
 $19
Investor-owned utilities, marketers, power producers538
 572
Energy cooperatives and municipalities525
 357
Other146
 80
Total$1,257
 $1,028
_________ 
(a)As of September 30, 2017,2018, credit collateral held from counterparties where Generation had credit exposure included $19$4 million of cash and $12$34 million of letters of credit. The credit collateral does not include non-liquid collateral.
ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on daily, updated forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price on a given day, the suppliers are required to 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 September 30, 2017,2018, ComEd’s net credit exposure to suppliers was less than $1$2 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 of the Exelon 20162017 Form 10-K 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 September 30, 2017,2018, PECO had no material 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 5 — Regulatory Matters for additional information.

129
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

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 September 30, 2017,2018, PECO had no material credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.
BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 20162017 Form 10-K 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 unsecured credit used by the suppliers represents BGE’s net credit exposure. The seller’s credit exposure is calculated each business day. As of September 30, 2017, BGE had no2018, BGE's net credit exposure to suppliers.suppliers was immaterial.
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 September 30, 2017, BGE had2018, BGE's credit exposure of less than $1 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.suppliers, was immaterial.
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 September 30, 2017,2018, Pepco’s, DPL's and ACE's net credit exposures to suppliers were immaterial.
Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL's and ACE's counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 20162017 Form 10-K 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 September 30, 2017, DPL had no2018, DPL's credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.suppliers was immaterial.
Collateral and Contingent-Related Features (All Registrants)
As part of the normal course of business, Generation routinely enters into physicalphysically or financially settled contracts for the purchase and sale of electric capacity, energy,electricity, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on

130
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

also enters into commodity transactions on exchanges (i.e., NYMEX, ICE). Thewhere 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-relatedcredit-risk related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
The aggregate fair value of all derivative instruments with credit-risk-relatedcredit-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 FeatureSeptember 30, 2017 December 31, 2016
Gross fair value of derivative contracts containing this feature(a)
$(916) $(960)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)
638
 627
       Net fair value of derivative contracts containing this feature(c)
$(278) $(333)
Credit-Risk Related Contingent Features September 30, 2018 December 31, 2017
Gross fair value of derivative contracts containing this feature(a)
 $(1,704) $(926)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)
 1,249
 577
Net fair value of derivative contracts containing this feature(c)
 $(455) $(349)
_________
(a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.
(b)Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
(c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
Generation had cash collateral posted of $460$255 million and letters of credit posted of $255$283 million and cash collateral held of $49$20 million and letters of credit held of $29$48 million as of September 30, 20172018 for external counterparties with derivative positions. Generation had cash collateral posted of $347$497 million and letters of credit posted of $284$293 million and cash collateral held of $24$35 million and letters of credit held of $28$33 million at December 31, 20162017 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 $1.8 billion and $1.9 billion as of September 30, 20172018 and December 31, 2016, respectively.2017. 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 September 30, 2017,2018, Generation's swaps were in a liability position with a fair value of $4 million and Exelon's swaps were in an asset position with a fair value of $6 million.$19 million and $9 million, respectively.
See Note 2625 — Segment Information of the Exelon 20162017 Form 10-K for furtheradditional information regarding the letters of credit supporting the cash collateral.

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

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 September 30, 2017,2018, ComEd held approximately $10$6 million in

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

collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's annual renewable energyREC and ZEC contracts, collateral postings are required to cover a fixed valuepercentage of the REC and ZEC contract value. As of September 30, 2018, ComEd held $20 million in collateral from suppliers for RECs only. In addition, underREC and ZEC contract obligations. Under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of September 30, 2017,2018, ComEd held approximately $21$19 million in collateral from suppliers for the form of cash and letters of credit as margin for both the annual and long-term REC obligations.renewable energy contracts. If ComEd lost its investment grade credit rating as of September 30, 2017,2018, it would have been required to post approximately $3$8 million of collateral to its counterparties. See Note 3 — Regulatory Matters of the Exelon 20162017 Form 10-K 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 September 30, 2017,2018, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of September 30, 2017,2018, PECO could have been required to post approximately $20$22 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 September 30, 2017,2018, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of September 30, 2017,2018, BGE could have been required to post approximately $28$31 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.
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 September 30, 2017,2018, DPL could have been required to post an additional amount of approximately $9$10 million of collateral to its natural gas counterparties.
ACE’sBGE's, Pepco's, DPL's and ACE's full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE, Pepco, DPL or ACE to post collateral.
11. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, BGE, Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes. 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.

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

requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Commercial Paper
The Registrants had the following amounts of commercial paper borrowings outstanding as ofSeptember 30, 20172018 and December 31, 2016:2017:
Commercial Paper Borrowings September 30, 2017 December 31, 2016 September 30, 2018 December 31, 2017
Exelon $118
 $688
 $209
 $427
Generation —
 620
BGE —
 45
 —
 77
PHI 118
 23
PHI(a)
 209
 350
Pepco —
 23
 64
 26
DPL 54
 —
 —
 216
ACE 65
 —
 145
 108
_________
(a)PHI reflects the commercial paper borrowings outstanding of Pepco, DPL and ACE.
Short-Term Loan Agreements
On January 13, 2016, PHI entered into a $500 million term loan agreement, which was amended on March 28, 2016. The net proceeds of the loan were used to repay PHI's outstanding commercial paper and for general corporate purposes. Pursuant to the loan agreement, as amended, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1%, and all indebtedness thereunder is unsecured. On March 23, 2017, the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement was fully repaid and the loan terminated.  On March 23, 2017, Exelon Corporate entered into a similar type term loan for $500 million which expiresexpired March 22, 2018.  The loan agreement was renewed on March 22, 2018.2018 and will expire on March 21, 2019. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1% and all indebtedness thereunder is unsecured.  The
On May 23, 2018, ACE entered into two term loan agreementagreements in the aggregate amount of $125 million, which expire on May 22, 2019. Pursuant to the term loan agreements, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.55% and all indebtedness thereunder is reflected in Exelon’s Consolidated Balance Sheet within Short-Term borrowings.unsecured.
Credit Agreements
On January 9, 2017,As of March 15, 2018, the credit agreement for Generation's $75 milliona Generation bilateral credit facility of $30 million was amended and restated to increase the overall facility size to $100 million and extend the maturity to January 2019.$95 million. This facility will solely be used by Generation to issue letters of credit.
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) converted its financial covenant from a debt to capitalization leverage ratio to an interest coverage ratio. On May 26, 2017,2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2022.2023.

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

Long-Term Debt
Issuance of Long-Term Debt
During the nine months ended September 30, 2017,2018, the following long-term debt was issued:
Company Type Interest Rate Maturity Amount Use of Proceeds Type Interest Rate Maturity Amount Use of Proceeds
Exelon 
Junior Subordinated Notes(a)
 3.50% June 1, 2022 $1,150
 Refinance Exelon's Junior Subordinated Notes issued in June 2014.
Generation Albany Green Energy Project Financing LIBOR + 1.25%
 November 17, 2017 $14
 Albany Green Energy biomass generation development.
Generation Energy Efficiency Project Financing 3.90% February 1, 2018 $17
 Funding to install energy conservation measures for the Naval Station Great Lakes project.
Generation Energy Efficiency Project Financing 2.61% September 30, 2018 $10
 Funding to install energy conservation measures for the Pensacola project.
Generation Energy Efficiency Project Financing 3.53% April 1, 2019 $8
 Funding to install energy conservation measures for the State Department project. Energy Efficiency Project Financing 3.72% November 30, 2018 $4
 Funding to install energy conservation measures for the Smithsonian Zoo project.
Generation Energy Efficiency Project Financing 3.72% May 1, 2018 $4
 Funding to install energy conservation measures for the Smithsonian Zoo project. Energy Efficiency Project Financing 3.17% October 31, 2018 $1
 Funding to install energy conservation measures in Brooklyn, NY.
Generation Senior Notes 2.95% January 15, 2020 $250
 Repay outstanding commercial paper obligations and for general corporate purposes. Energy Efficiency Project Financing 2.61% September 30, 2018 $5
 Funding to install energy conservation measures for the Pensacola project.
Generation Senior Notes 3.40% March 15, 2022 $500
 Repay outstanding commercial paper obligations and for general corporate purposes. Energy Efficiency Project Financing 4.17% January 1, 2019 $1
 Funding to install energy conservation measures for the General Services Administration Philadelphia project.
Generation ExGen Texas Power Nonrecourse Debt LIBOR + 4.75%
 September 18, 2021 $6
 Funding for general corporate purposes. Energy Efficiency Project Financing 4.26% May 1, 2019 $3
 Funding to install energy conservation measures for the National Institutes of Health Multi-Buildings Phase II project.
ComEd First Mortgage Bonds, Series 122 2.95% August 15, 2027 $350
 Refinance maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes. First Mortgage Bonds, Series 124 4.00% March 1, 2048 $800
 Refinance one series of maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and to fund general corporate purposes.
ComEd First Mortgage Bonds, Series 123 3.75% August 15, 2047 $650
 Refinance maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes. First Mortgage Bonds, Series 125 3.70% August 15, 2028 $550
 Repay a portion of ComEd’s outstanding commercial paper obligations and to fund general corporate purposes.
PECO First and Refunding Mortgage Bonds 3.70% September 15, 2047 $325
 General corporate purposes. First and Refunding Mortgage Bonds 3.90% March 1, 2048 $325
 Refinance a portion of maturing mortgage bonds.
PECO Loan Agreement 2.00% June 20, 2023 $50
 Funding to implement Electric Long-term Infrastructure Improvement Plan.
PECO First and Refunding Mortgage Bonds 3.90% March 1, 2048 $325
 Satisfy short-term borrowings from the Exelon intercompany money pool and for general corporate purposes.
BGE Notes 3.75% August 15, 2047 $300
 Redeem $250 million in principal amount of the 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 issued by BGE's affiliate BGE Capital Trust II, repay commercial paper obligations and for general corporate purposes.
 Senior Notes 4.25% September 15, 2048 $300
 Repay commercial paper obligations and for general corporate purposes.
Pepco Energy Efficiency Project Financing 3.30% December 15, 2017 $2
 Funding to install energy conservation measures for the DOE Germantown project. First Mortgage Bonds 4.27% June 15, 2048 $100
 Repay existing indebtedness and for general corporate purposes.
Pepco First Mortgage Bonds 4.15% March 15, 2043 $200
 Funding to repay outstanding commercial paper and for general corporate purposes.
DPL First Mortgage Bonds 4.27% June 15, 2048 $200
 Repay existing indebtedness and for general corporate purposes.
_________
(a)See the Junior Subordinated Notes discussion below for further information.
EGTP Nonrecourse Debt
In September 2014, EGTP, an indirect subsidiaryOn October 16, 2018, ACE issued $350 million of Exelon4.00% First Mortgage Bonds due October 15, 2028. The proceeds will be used to refinance ACE’s 7.75% First Mortgage Bonds due November 15, 2018, reduce short-term borrowings and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. The net proceeds were distributed to Generation for general businesscorporate purposes.
On November 1, 2018, Pepco issued $100 million of 4.31% First Mortgage Bonds due November 1, 2048. The loan is scheduledproceeds will be used to maturerepay existing indebtedness and for general corporate purposes.
12. Income Taxes (All Registrants)
Corporate Tax Reform (All Registrants)
On December 22, 2017, President Trump signed the TCJA into law. The TCJA makes many significant changes to the Internal Revenue Code, including, but not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) creating a 30% limitation on September 18, 2021.  The term loan bearsdeductible interest at a variable rate equalexpense (not applicable to LIBOR plus 4.75%, subjectregulated utilities); (3) allowing 100% expensing for the cost of qualified property (not applicable to a 1% LIBOR floor with interest payable quarterly. As of September 30,regulated utilities); (4) eliminating the domestic production activities deduction; (5)

134
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

2017, $660 million was outstanding. As parteliminating the corporate alternative minimum tax and changing how existing alternative minimum tax credits can be realized; and (6) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017. The most significant change that impacts the Registrants is the reduction of the agreement, a revolving credit facility was established for the amount of $20 million available through, and scheduledcorporate federal income tax rate from 35% to mature on September 18, 2019. In addition21% beginning January 1, 2018.
Pursuant 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 portionenactment of the interestTCJA, the Registrants remeasured their existing deferred income tax balances as of December 31, 2017 to reflect the decrease in the corporate income tax rate exposure in connection with this financing, as required by the debt covenants. See Note 10 — Derivative Financial Instruments for additional information regarding interest rate swaps.
On May 2, 2017, EGTP entered into a consent agreement with its lenders,from 35% to 21%, which resulted in a material decrease to their net deferred income tax liability balances as shown in the outstanding debt balance being classified as Long-term debt due within one year on Exelon'stable below. Generation recorded a corresponding net decrease to income tax expense, while the Utility Registrants recorded corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and Generation's Consolidated Balance Sheets.an adjustment to income tax expense for all other amounts. The amount and timing of potential settlements of the established net regulatory liabilities will be determined by the Utility Registrants’ respective rate regulators, subject to certain IRS “normalization” rules. See Note 4 - Mergers, Acquisitions and Dispositions and Note 6 - Impairment of Long-Lived Assets— Regulatory Matters for moreadditional information.
Junior Subordinated Notes
In June 2014, Exelon issued $1.15 billionThe Registrants assessed the majority of junior subordinated notesthe applicable provisions in the formTCJA and have recorded the associated impacts as of 23 million equity units at a stated amountDecember 31, 2017. As discussed further below, under SAB 118 issued by the SEC in December 2017, the Registrants have recorded provisional income tax amounts as of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract.   As contemplated inDecember 31, 2017 for changes pursuant to the June 2014 equity unit structure, in April 2017, Exelon completedTCJA related to depreciation for which the remarketingimpacts could not be finalized upon issuance of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”).  Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of September 30, 2017. See Note 17 - Earnings Per Share and EquityRegistrants’ financial statements, but for further information on the issuance of common stock.
Albany Green Energy Project
During the third quarter of 2017, upon completion of AGE, Generation retired $228 million of its LIBOR + 1.25% outstanding debt balance, which included $6 million of accumulated interest. Pursuant to the financing terms entered into by AGE in the second quarter of 2015, the entire financing balance plus accumulated interest was due upon substantial completion, but no later than November 17, 2017. See Note 3 - Variable Interest Entities for more details regarding AGE.
BGE Redemption of Trust Preferred Securitiesreasonable estimates could be determined.
On August 3, 2018, the U.S. Department of Treasury in conjunction with the IRS released proposed regulations clarifying the immediate expensing depreciation provisions enacted by the TCJA, specifically that regulated utility property acquired after September 27, 2017 and placed in service by December 31, 2017 qualifies for 100% expensing. Until the proposed regulations are finalized, taxpayers may rely on the proposed regulations for tax years ending after September 28, 2017, BGE redeemed all2017.
While the Registrants have recorded the impacts of the outstanding shares of BGE Capital Trust II 6.20% Preferred Securities (“Securities”), pursuant to the optional redemption provisionsTCJA based on their interpretation of the Indenture underprovisions as enacted, it is expected that Treasury and the IRS will issue additional interpretative guidance in the future which could result in changes to previously finalized provisions. At this time, many of the Securities were issued. The redemption price per share was $25.19,states in which equaledExelon does business have issued guidance regarding TCJA and the stated value per share plus accrued and unpaid dividends to, but excluding, the redemption date. No dividends on the Securities redeemed were accrued on or after the redemption date, nor did any interest accrue on amounts held to pay the redemption price.impact is not material.

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

12.    Income Taxes (All Registrants)The one-time impacts recorded by the Registrants to remeasure their deferred income tax balances at the 21% corporate federal income tax rate as of December 31, 2017 are presented below. The impact of the August 3, 2018 proposed regulations to these balances is not material.
 
Exelon(b)
 Generation ComEd PECO BGE PHI Pepco DPL ACE
Net Decrease to Deferred Income Tax Liability Balances$8,624
 $1,895
 $2,819
 $1,407
 $1,120
 $1,944
 $968
 $540
 $456
 Exelon Generation ComEd 
PECO(c)
 BGE PHI Pepco DPL ACE
Net Regulatory Liability Recorded(a)
$7,315
 N/A $2,818
 $1,394
 $1,124
 $1,979
 $976
 $545
 $458
 
Exelon(b)
 Generation ComEd PECO BGE PHI Pepco DPL ACE
Net Deferred Income Tax Benefit/(Expense) Recorded$1,309
 $1,895
 $1
 $13
 $(4) $(35) $(8) $(5) $(2)
__________
(a)Reflects the net regulatory liabilities recorded on a pre-tax basis before taking into consideration the income tax benefits associated with the ultimate settlement with customers.
(b)Amounts do not sum across due to deferred tax adjustments recorded at the Exelon Corporation parent company, primarily related to certain employee compensation plans.
(c)Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO was in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. See Note 6 - Regulatory Matters for additional information.
The net regulatory liabilities above include (1) amounts subject to IRS “normalization” rules that are required to be passed back to customers generally over the remaining useful life of the underlying assets giving rise to the associated deferred income taxes, and (2) amounts for which the timing of settlement with customers is subject to determinations by the rate regulators. The table below sets forth the Registrants’ estimated categorization of their net regulatory liabilities as of December 31, 2017. The amounts in the table below are shown on an after-tax basis reflecting future net cash outflows after taking into consideration the income tax benefits associated with the ultimate settlement with customers.
 Exelon ComEd 
PECO(a)
 BGE PHI PEPCO DPL ACE
Subject to IRS Normalization Rules$3,040
 $1,400
 $533
 $459
 $648
 $299
 $195
 $153
Subject to Rate Regulator Determination1,694
 573
 43
 324
 754
 391
 194
 170
Net Regulatory Liabilities$4,734
 $1,973
 $576
 $783
 $1,402
 $690
 $389
 $323
__________
(a)Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants. See Note 6 - Regulatory Matters for additional information.
The net regulatory liability amounts subject to the IRS normalization rules generally relate to property, plant and equipment with remaining useful lives ranging from 30 to 40 years across the Utility Registrants.  For the other amounts, the pass back period is subject to determinations by the rate regulators. See Note 6 - Regulatory Matters for the status of and information regarding the Registrants' TCJA-related regulatory filings.

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

Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:
 Three Months Ended September 30, 2017
           Successor      
 Exelon
Generation
ComEd
PECO
BGE PHI Pepco DPL ACE
U.S. Federal statutory rate35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit2.2 5.6 6.6 (0.1) 5.3 5.1 2.2 5.3 5.6
Qualified nuclear decommissioning trust fund income2.6 5.8 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference
(1.1) (2.2) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.4)
Plant basis differences(2.6) — (0.3) (14.6) (0.8) (4.9) (6.7) (1.9) (3.4)
Production tax credits and other credits(2.2) (4.8) — — — — — — —
Noncontrolling interests0.5 1.0 — — — — — — —
FitzPatrick bargain purchase gain(0.2) (0.4) — — — — — — —
Other(0.1) 0.3 (0.2) (0.2) (0.2) 0.2 — (0.2) 0.1
Effective income tax rate34.1% 40.3% 40.9% 20.0% 39.2% 35.2% 30.4% 38.0% 36.9%
Three Months Ended September 30, 2016
 Successor Three Months Ended September 30, 2018
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon
Generation
ComEd
PECO
BGE PHI Pepco DPL ACE
U.S. Federal statutory rate35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:  
State income taxes, net of Federal income tax benefit3.8 2.6 7.3 2.4 5.2 5.6 5.6 5.2 6.1(1.2) (9.0) 8.3 (3.6) 7.3 0.2 1.0 6.6 7.3
Qualified nuclear decommissioning trust fund income4.0 7.8 — — — — — — —2.4 5.8 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.9) (1.6) (0.6) (0.1) (0.2) (0.1) — (0.2) (0.1)(0.6) (1.1) (0.2) (0.1) — (0.2) (0.1) (0.3) (0.3)
Plant basis differences(3.0) — (1.9) (6.7) (0.5) (5.0) (6.7) (1.3) (4.6)(2.5) — (0.3) (15.2) (0.8) (2.0) (3.4) (0.7) (1.3)
Production tax credits and other credits(2.9) (5.7) (0.1) — — — — — —(1.2) (2.9) (0.1) — — — — — —
Noncontrolling interest0.2 0.5 — — — — — — —
Statute of limitations expiration

(0.1) 0.3 — — — — — — —
Penalties4.3 — 27.2 — — — — — —
Merger expenses

(0.6) — — — — (5.7) (2.3) (8.6) (2.9)
Noncontrolling interests(1.1) (2.8) — — — — — — —
Excess deferred tax amortization(6.8) — (7.8) (4.6) (7.9) (17.7) (21.2) (14.0) (15.4)
Tax Cuts and Jobs Act of 20171.3 3.5 — — — 0.2 0.1 — —
Other(0.8) (0.5) 0.1 0.1 (0.4) (0.7) (0.9) 0.1 (0.6)3.2 5.6 0.3 0.9 2.6 0.6 0.3 0.6 0.3
Effective income tax rate39.0% 38.4% 67.0% 30.7% 39.1% 29.1% 30.7% 30.2% 32.9%14.5% 20.1% 21.2% (1.6)% 22.2% 2.1% (2.3)% 13.2% 11.6%

136
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Nine Months Ended September 30, 2017
 Successor 
Three Months Ended September 30, 2017(a)
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:  
State income taxes, net of Federal income tax benefit0.7 2.1 5.9 (0.1) 5.2 4.9 3.0 5.1 5.62.2 5.6 6.6 (0.1) 5.3 5.1 2.2 5.3 5.6
Qualified nuclear decommissioning trust fund income4.0 14.0 — — — — — — —2.6 5.8 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.9) (2.7) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.4)(1.1) (2.2) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.4)
Plant basis differences(3.4) — (0.3) (14.4) (0.8) (4.6) (6.3) (1.8) (3.4)(2.6) — (0.3) (14.6) (0.8) (4.9) (6.7) (1.9) (3.4)
Production tax credits and other credits(1.8) (6.2) — — — — — — —(2.2) (4.9) — — — — — — —
Noncontrolling interests0.2 0.7 — — — — — — —0.5 1.1 — — — — — — —
Merger expenses(5.4) (2.5) — — — (11.8) (8.0) (10.0) (23.0)
FitzPatrick bargain purchase gain(3.2) (11.2) — — — — — — —
Like-kind exchange(a)
(1.7) — 1.7 — — — — — —
Fitzpatrick bargain purchase gain(0.2) (0.4) — — — — — — —
Other— (0.4) 0.2 — 0.2 — (0.3) 0.6 (0.3)(0.1) 0.3 (0.2) (0.2) (0.2) 0.2 — (0.2) 0.1
Effective income tax rate23.5% 28.8% 42.3% 20.4% 39.5% 23.3% 23.3% 28.7% 13.5%34.1% 40.3% 40.9% 20.0% 39.2% 35.2% 30.4% 38.0% 36.9%
 Nine Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit1.7 (2.6) 8.2 (3.6) 6.6 2.7 2.4 6.5 7.3
Qualified nuclear decommissioning trust fund income0.9 2.6 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.9) (2.2) (0.2) (0.1) (0.1) (0.2) (0.1) (0.3) (0.3)
Plant basis differences(2.7) — (0.1) (15.4) (0.7) (1.9) (2.9) (0.7) (1.3)
Production tax credits and other credits(1.8) (5.1) (0.1) — — — — — —
Noncontrolling interests(1.1) (3.2) — — — — — — —
Excess deferred tax amortization(6.1) — (7.6) (3.4) (8.1) (14.5) (16.5) (11.0) (14.0)
Tax Cuts and Jobs Act of 20170.2 1.3 (0.2) — — 0.3 — — —
Other0.4 2.0 0.1 — 0.9 0.3 — 0.4 0.9
Effective income tax rate11.6% 13.8% 21.1% (1.5)% 19.6% 7.7% 3.9% 15.9% 13.6%

137
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

 Successor Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
Nine Months Ended September 30, 2017(a)
Exelon Generation ComEd PECO BGE Pepco 
DPL(b)
 
ACE(b)
 
PHI(b)
 PHIExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:  
State income taxes, net of Federal income tax benefit(c)
2.5 2.6 5.4 1.3 4.8 23.0 310.5 5.5 4.4 11.9
State income taxes, net of Federal income tax benefit0.7 2.2 5.9 (0.1) 5.2 4.9 3.0 5.1 5.6
Qualified nuclear decommissioning trust fund income4.8 8.8 — — — — — — — —4.0 13.6 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(1.3) (2.0) (0.3) (0.1) (0.2) (0.2) (17.9) 0.5 0.5 (0.9)(0.9) (2.7) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.4)
Plant basis differences(4.5) — (0.6) (8.8) (3.3) (29.0) (98.6) 7.8 17.5 (13.5)(3.4) — (0.3) (14.4) (0.8) (4.6) (6.3) (1.8) (3.4)
Production tax credits and other credits(4.1) (7.6) — — — — — — — —(1.8) (6.0) — — — — — — —
Noncontrolling interest0.5 0.9 — — — — — — — —
Statute of limitations expiration
(0.5) (1.7) — — — — — — — —
Penalties2.3 — 5.6 — — — — — — —
Merger expenses
6.2 — — — — 36.7 635.9 (35.4) (49.8) 11.1
Noncontrolling interests0.1 0.3 — — — — — — —
Merger expenses(c)

(5.4) (2.4) — — — (11.8) (8.0) (10.0) (23.0)
FitzPatrick bargain purchase gain(3.2) (10.9) — — — — — — —
Like-Kind Exchange(b)
(1.7) — 1.7 — — — — — —
Other(1.8) (2.1) — (1.5) — (2.5) 35.1 0.4 1.4 3.60.1 (0.4) 0.2 — 0.2 — (0.3) 0.6 (0.3)
Effective income tax rate39.1% 33.9% 45.1% 25.9% 36.3% 63.0% 900.0%
13.8%
9.0% 47.2%23.5% 28.7% 42.3% 20.4% 39.5% 23.3% 23.3% 28.7% 13.5%
_________
(a)See Like-Kind Exchange withinExelon retrospectively adopted the Other Income Tax Matters section below for further details.new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. The effective income tax rates are recast to reflect the impact of the new standard.
(b)DPLExelon and ACE recognized a loss before income taxes forComEd recorded the nine months ended September 30, 2016, and PHI recognized a loss before income taxes forimpact of the periodIRS's finalization of March 24, 2016, through September 30, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.LKE computation in the second quarter of 2017.
(c)Includes a remeasurement of uncertain federal and state income tax positions for Pepco and DPL.positions.
Accounting for Uncertainty in Income Taxes
The Registrants have the following unrecognized tax benefits as of September 30, 20172018 and December 31, 2016:2017:
           Successor      
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
September 30, 2017$738
 $468
 $2
 $—
 $120
 $120
 $59
 $21
 $8
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
September 30, 2018$804
 $527
 $2
 $—
 $120
 $134
 $67
 $21
 $14
           Successor      
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
December 31, 2016$916
 $490
 $(12) $—
 $120
 $172
 $80
 $37
 $22
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
December 31, 2017$743
 $468
 $2
 $—
 $120
 $125
 $59
 $21
 $14
Exelon establishedAs a liability forresult of a court decision issued in July 2018 to an uncertainunrelated taxpayer, Exelon's and Generation’s unrecognized federal and state tax position associated withbenefits increased in the third quarter of 2018 by approximately $71 million. Approximately $20 million of this increase impacted Exelon's and Generation’s effective tax deductibilityrate and resulted in a charge to earnings in the third quarter of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation in 2012 and PHI in 2016. In the2018.

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

first quarter 2017, as a part of its examination of Exelon’s return, the IRS National Office issued guidance concurring with Exelon’s position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million, and $22 million, respectively, as of September 30, 2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.
Exelon reduced the liability related to the uncertain tax position associated with the like-kind exchange in the second quarter of 2017. Please see the Other Income Tax Matters section below for additional details related to the like-kind exchange adjustments made in the second quarter of 2017.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
Like-Kind Exchange
As of September 30, 2017,2018, Exelon and ComEd have approximately $39$33 million and $2 million, respectively, of unrecognized federal and state income tax benefits that could significantly decrease within the 12 months after the reporting date duerelated to a final resolution of the like-kind exchange litigation described further below. The recognitionIf Exelon decides not to appeal the October 2018 U.S. Court of theseAppeals for the Seventh Circuit's decision, Exelon's and ComEd's unrecognized tax benefits wouldwill decrease Exelon and ComEd's effective tax rate.in the fourth quarter. See below for further details.
Settlement of Income Tax PositionsAudits, Refund Claims, and Litigation
As of September 30, 2017,2018, Exelon, Generation, BGE, PHI Pepco, DPL, and ACE have approximately $676$515 million, $469$501 million, $120 million, $88 million, $59 million, $21$14 million and $8$14 million of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, and the outcomes of pending court cases. Of the above unrecognized tax benefits, Exelon and Generation have $462$473 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefits related to BGE, DPL,PHI and ACE, and a portion of Pepco, if recognized, may be included in future regulated base rates and that portion would have no impact to the effective tax rate.
As of September 30, 2018, Exelon, Generation, BGE, PHI, Pepco and DPL have approximately $241 million, $33 million, $120 million, $88 million, $67 million, and $21 million, respectively, of unrecognized state tax benefits that will decrease in the fourth quarter of 2018 due to the receipt of favorable guidance with respect to the deductibility of certain depreciable fixed assets.  The recognition of these tax benefits will decrease the effective tax rate at Exelon and Generation in the fourth quarter of 2018, which will result in an income tax benefit of approximately $26 million.  The recognition of the tax benefits related to BGE, PHI, Pepco and DPL will be offset by corresponding regulatory liabilities and that portion will have no immediate impact to their effective tax rate.
Other Income Tax Matters
Like-Kind Exchange (Exelon and ComEd)
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. As previously disclosed, Exelon terminated its investment in one of the leases in 2014 and the remaining two leases were terminated in 2016.
The IRS 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 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”listed transaction that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRSshelter. Thus, they disagreed with Exelon's position and 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 theentire 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.
On September 30,$1.2 billion was taxable in 1999. In 2013, the IRS issued a notice of deficiency to Exelon for the like-kind exchange position.and Exelon filed a petition on December 13, 2013 to initiate litigation in the United States Tax Court (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,Court. In 2016, the Tax Court rejected Exelon’s position in the case and ruledheld that Exelon was not entitled to defer gain on the transaction. In addition contrary to Exelon’s evaluation that the penalty was unwarranted,tax and interest related to the gain deferral, the Tax Court also ruled that Exelon iswas liable for the penalty and interest due on the asserted penalty. In June of 2017, the IRS finalized its computation of tax,$90 million in penalties and interest owed byon the penalties. Exelon pursuant tohas fully paid the amounts assessed resulting from the Tax Court’sCourt decision.
In September of 2017, Exelon appealed thisthe Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the Tax Court’s decision. Exelon is evaluating whether to pursue any further appeals of the decision.

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

InState Income Tax Law Changes
On April 24, 2018, Maryland enacted companion bills, House Bill 1794 and Senate Bill 1090, providing for a phase in of a single sales factor apportionment formula from the first quarter of 2013, Exelon concluded that it was no longer more likely than not that the like-kind exchange position would be sustained and recorded charges to earnings representing the amount of interest expense (after-tax) and incrementalcurrent three factor formula for determining an entity's Maryland state income tax expense that wouldtaxes. The single sales factor will be payablefully phased in the event Exelon is unsuccessful in litigation. Exelon agreed to hold ComEd harmless from any unfavorable impacts on ComEd’s equity of the after-tax interest and penalty amounts.by 2022.
Prior to the Tax Court’s decision, however, Exelon did not believe it was likely a penalty would be assessed based on applicable case law and the facts of the transaction.  As a result, no charge had been recorded for the penalty or for after-tax interest on the penalty. 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 ultimate imposition of 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 from the like-kind exchange position, ComEd recorded on its Consolidated Balance Sheets as of September 30, 2016, an additional $150 million receivable and non-cash equity contributions from Exelon.
As a result of the IRS’s finalization of its computation in the second quarter 2017, Exelon recorded a benefit to earnings of approximately $26 million, consisting of an income tax benefit of $50 million and a reduction of penalties of $2 million, partially offset by after-tax interest expense of $26 million, while ComEd recorded a charge to earnings of approximately $23 million, consisting of income tax expense of $15 million and after-tax interest expense of $8 million.
In the second quarter of 2017,2018, Exelon, amended its agreement with ComEdGeneration, PHI, Pepco and DPL recorded a one-time increase to also hold ComEd harmless fordeferred income taxes of approximately $16 million, $5 million, $17 million, $16 million and $1 million, respectively. At PHI, Pepco and DPL, the unfavorable impacts on its equity fromincrease to the additionalMaryland deferred income tax amounts owedliability was offset by ComEd asregulatory assets. Further, the change in tax law is not expected to have a resultmaterial ongoing impact to Exelon's, Generation's, PHI's, Pepco's or DPL's future results of the IRS’s finalization of its computation related to the like-kind exchange position. Accordingly, in the second quarter of 2017, ComEd recorded an additional receivable and non-cash equity contribution from Exelon for the total $23 million. As of June 30, 2017, ComEd had a total receivable from Exelon pursuant to the hold harmless agreement of $369 million, which was included in Current Receivables from Affiliates on ComEd’s Consolidated Balance Sheet.
Exelon expects to pay the tax, penalties and interest of approximately $1.3 billion related to the like-kind exchange, including $300 million attributable to ComEd, in the fourth quarter of 2017. While Exelon will receive a tax benefit of approximately $350 million associated with the deduction for the interest, Exelon currently has 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 approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts on ComEd’s equity from the like-kind exchange position. Following a final appellate decision, which is expected in 2018, Exelon expects to receive approximately $60 million related to final interest computations.
Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. Any remaining amounts due to the IRS will be paid by Exelon in the fourth quarter of 2017. 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 the third quarter of 2017, the $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuant to the hold harmless agreement, was settled with Exelon. No recovery will be sought from ComEd customers for any interest, penalty, or additional income tax payment amounts resulting from 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. In the first quarter of 2016, Exelon terminated its interests in the remaining two municipal-owned electric generation properties in exchange for $360 million.operations.
Long-Term Marginal State Income Tax Rate (Exelon, Generation, ComEd, PHI and Pepco)
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

140
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

and/or significant operational changes. Exelon's, PHI's and Pepco's long-term marginal state income tax rate were revised in the first quarter of 2017 as a result of a statutory rate change in Washington, D.C. As a result, Exelon, PHI and Pepco recorded a one-time decrease to Deferred income tax liability of $28 million, $8 million, and $8 million, respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, Exelon, PHI and Pepco recorded a corresponding regulatory liability of $8 million, in the Consolidated Balance Sheets. In addition, Exelon recorded a decrease to Income tax expense of $20 million, net of federal taxes, in the Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2017.
In the third quarter of 2017,2018, Exelon reviewed and updated its marginal state income tax rates based on 20162017 state apportionment rates. In addition, Exelon, Generation and ComEd recorded the impacts of Illinois’ statutory rate change, which increased the total corporate income tax rate from 7.75% to 9.5% effective July 1, 2017. As a result of the rate changes, in the third quarter of 2017,2018, Exelon, Generation, PHI and ComEdDPL recorded a one-time decrease to deferred income taxes of approximately $50 million, $53 million, $4 million and $2 million, respectively. Pepco recorded a one-time increase to Deferred incomedeferred incomes taxes of approximately $250$1 million. Exelon, PHI and DPL recorded a corresponding regulatory liability of approximately $1 million, $20$1 million and $270$2 million, respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, each of Exelon and ComEdrespectively. Pepco recorded a corresponding regulatory asset of $272approximately $1 million. Further,In the third quarter of 2018, Exelon, Generation and PHI recorded a decrease to Incomeincome tax expense of approximately $20 million and Generation recorded an increase to Income tax expense of approximately $20 million (each net(net of federal taxes) in their Consolidated Statements of Operationsapproximately $50 million, $53 million and Comprehensive Income for the three and nine months ended September 30, 2017. The Illinois statutory rate increase is not expected to have a material ongoing impact to Exelon’s, Generation’s or ComEd’s future results of operations.$3 million, respectively.
13. Nuclear DecommissioningAsset Retirement Obligations (Exelon, Generation and Generation)Pepco)
Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.
The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 20162017 to September 30, 2017:2018:
Nuclear decommissioning ARO at December 31, 2016(a)
$8,734
Acquisition of FitzPatrick444
Accretion expense342
Net decrease due to changes in, and timing of, estimated cash flows(148)
Costs incurred to decommission retired plants(6)
Nuclear decommissioning ARO at September 30, 2017(a)
$9,366
Nuclear decommissioning ARO at December 31, 2017 (a)
$9,662
Oyster Creek transferred to Liabilities held for sale(783)
Accretion expense357
Net increase due to changes in, and timing of, estimated future cash flows116
Costs incurred related to decommissioning plants(35)
Nuclear decommissioning ARO at September 30, 2018 (a)
$9,317
_________
(a)Includes $12 million and $10$13 million for the current portion of the ARO at September 30, 20172018 and December 31, 2016,2017, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During the nine months ended September 30, 2017, Generation’s nuclear ARO increased by approximately $632 million. The increase primarily reflects the net impacts of the acquisition of FitzPatrick, the announced early retirement of TMI, year-to-date accretion of the ARO liability due to the passage of time and ARO updates completed during 2017 to reflect changes in amounts and timing of estimated decommissioning cash flows.
In the first quarter of 2017, a preliminary estimate of $417 million was recorded for the fair value of FitzPatrick’s ARO. In the third quarter of 2017, an adjustment was recorded to increase the FitzPatrick ARO valuation by $27 million to $444 million to reflect updated cost estimate inputs from a third-party engineering firm. For additional details on the acquisition of FitzPatrick, see Note 4 - Mergers, Acquisitions and Dispositions.

The net $148 million decrease due to changes in, and timing of, estimated cash flows was driven by multiple adjustments throughout the period, some with offsetting impacts. These adjustments include a $180 million decrease

141
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

During the nine months ended September 30, 2018, Generation’s total nuclear ARO decreased by approximately $345 million, primarily reflecting the reclassification of Oyster Creek ARO as Liabilities held for refinements in estimated fleet wide labor costs expectedsale on Exelon's and Generation's Consolidated Balance Sheets following the announced agreement to be incurred for certain on-site personnel during decommissioning as well as decreases resulting from updatessell Oyster Creek, offset by the accretion of the ARO liability due to the cost studiespassage of Clintontime, and Quad Cities. These decreases were partially offset by a $138the impacts of ARO updates completed during 2018. The $116 million increase in TMI's ARO liability associated with the May 30, 2017 announcement to early retire the unit on September 30, 2019. The increase in the ARO liability for TMI incorporatesduring 2018 due to changes in the early shutdown date, increases the probabilitiesamounts and timing of longer termestimated decommissioning scenarios, and reflects ancash flows includes a $32 million increase in the estimated costsfirst quarter for the impact of the early retirement of Oyster Creek and a $84 million increase in the third quarter for the remeasurement of the ARO to decommission based on an updated decommissioning cost study. Refer toreflect the announced pending sale of Oyster Creek. See Note 74 — Mergers, Acquisitions and Dispositions and Note 8 - Early Nuclear Plant Retirements for additional information regarding the announced early retirement of TMI.information.
Nuclear Decommissioning Trust Fund Investments (Exelon and Generation)
NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.
The NDT funds associated with Generation’s nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment (NDCA) withThe most recent rate adjustment occurred on January 1, 2018, and the PAPUC proposing aneffective rates currently yield annual recovery from customerscollections of approximately $4 million. This amount reflects a decrease from the current approved annual collection of approximately $24 million primarily dueThe next five-year adjustment is expected to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the newbe reflected in rates will becharged to PECO customers effective January 1, 2018.2023. See Note 16 -15 — Asset Retirement Obligations of Exelon's 20162017 Form 10-K, for information regarding the amount collected from PECO ratepayers for decommissioning costs.
Exelon and Generation had NDT fund investments totaling $12,966$12,584 million and $11,061$13,349 million at September 30, 20172018 and December 31, 2016,2017, respectively. The increasedecrease is primarily driven by the reclassification of $903 million of Oyster Creek NDT as Assets held for sale on Exelon's and Generation's Consolidated Balance Sheets, partially offset by improved market performanceperformance. See Note 4 - Mergers, Acquisitions and Dispositions for additional information regarding the acquisitionannounced pending sale of FitzPatrick.Oyster Creek. The NDT fund investments include $120 million and $77 million for the current portion of the NDT at September 30, 2018 and December 31, 2017, respectively, which are included in Other current assets on Exelon's and Generation's Consolidated Balance Sheets.

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

The following table provides net unrealized gains (losses) on NDT funds for the three and nine months ended September 30, 20172018 and 2016:2017:
 Exelon and Generation Exelon and Generation
 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units(a)
$44
 $155
 $253
 $286
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c)
111
 116
 347
 216
 Exelon and Generation Exelon and Generation
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units(a)
$(66) $44
 $(335) $253
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c)
72
 111
 (143) 347
 
_________
(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 $4$9 million and $5$4 million of net unrealized losses related to the Zion Station pledged assets for the three months ended September 30, 20172018 and 20162017, respectively. Excludes $5$7 million and $2$5 million of net unrealized losses related to the Zion Station pledged assets for the nine months ended September 30, 20172018 and 2016,2017, respectively. Net unrealized losses related to Zion Station pledged assets are included in Other current liabilities and Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets in 2017 and 2016, respectively.Sheets.
(c)Net unrealized gains (losses) related to Generation’s NDT funds with Non-Regulatory Agreement Units are included withinin Other, net inon 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 inon 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 withinin Other, net inon Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.

142
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Refer toSee Note 3 — Regulatory Matters and Note 2726 — Related Party Transactions of the Exelon 20162017 Form 10-K 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 (Exelon and Generation)
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 completing certain decommissioning activities at Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 1615 — Asset Retirement Obligations of the Exelon 20162017 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction.
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, are recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. Following ZionSolutions’ completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and will complete all remaining decommissioning activities associated with the SNF dry storage facility.

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

Generation has a liability of approximately $112$118 millionwhich is included within the nuclear decommissioning ARO at September 30, 2017.2018. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at September 30, 20172018 and December 31, 2016:2017:
Exelon and GenerationExelon and Generation
September 30, 2017 December 31, 2016September 30, 2018 December 31, 2017
Carrying value of Zion Station pledged assets(a)$57
 $113
$9
 $39
Payable to Zion Solutions(a)(c)
53
 104
9
 37
Current portion of payable to Zion Solutions(b)
53
 90
Cumulative withdrawals by Zion Solutions to pay decommissioning costs(c)
928
 878
Cumulative withdrawals by Zion Solutions to pay decommissioning costs(d)
965
 942
_________
(a)Included in Other current assets within Exelon's and Generation's Consolidated Balance sheets.
(b)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.
(b)(c)Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.
(c)(d)Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings.
NRC Minimum Funding Requirements (Exelon and Generation)
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.
Generation filed its biennial decommissioning funding status report with the NRC on March 30, 2017 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions (see Zion Station Decommissioning above). The status report demonstrated adequate decommissioning funding assurance for all units except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund in addition to collections from PECO ratepayers. As discussed under Nuclear Decommissioning Trust Fund Investments above, the amount collected from PECO ratepayers has been adjusted in the March 31, 2017 filing to the PAPUC which was approved on August 8, 2017 and will be effective January 1, 2018.

On March 28, 2018, Generation submitted its annual decommissioning funding status report with the NRC for shutdown reactors, reactors within five years of shut down except for Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above), and reactor involved in an acquisition. This report reflected the status of decommissioning funding assurance as of December 31, 2017 and included an update for the acquisition of FitzPatrick on March 31, 2017, the early retirement of TMI announced on May 30, 2017, an adjustment for the February 2, 2018 announced retirement date of Oyster Creek, and the updated status of Peach Bottom Unit 1 based on the new collections rate described above. As of December 31, 2017, Generation provided adequate decommissioning funding assurance for all of its shutdown reactors, reactors within five years of shutdown, and reactor involved in an acquisition.
143
TableGeneration will file its next decommissioning funding status report for all units with the NRC by March 31, 2019. This report will reflect the status of Contentsdecommissioning funding assurance as of December 31, 2018. A shortfall at any unit could necessitate that Generation address the shortfall by, among other

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

Generation will file its next decommissioning funding status report with the NRC by March 31, 2018 for shutdown reactors and reactors within five years of shutdown. This report will reflect the status of decommissioning funding assurance as of December 31, 2017 and will include the impact of the announced early retirement of TMI. A shortfall could necessitate that Exelon postthings, obtaining a parental guarantee for Generation’sGeneration's share of the funding assurance. However, the amount of any required guarantee or other assurance will ultimately depend on the decommissioning approach, adopted at TMI, the associated level of costs, and the decommissioning trust fund investment performance going forward.
Non-Nuclear Asset Retirement Obligations (Pepco)
Pepco has AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. In the third quarter of 2018, Pepco recorded an increase of $22 million in Operating and maintenance expense primarily related to asbestos identified at its Buzzard Point property as part of an annual ARO study. Buzzard Point is a waterfront property in the District of Columbia occupied by an active substation and former Pepco operated steam plant building, which Pepco retired and closed in 1981. Pepco’s AROs were $38 million and $3 million at September 30, 2018 and December 31, 2017, respectively.
14. Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all current employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective March 23, 2016,January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018, most newly-hired Generation and BSC non-represented employees are not eligible for pension benefits and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon became the sponsor of all of PHI's defined benefit pensioncontribution savings plan. Effective January 1, 2018, most newly-hired non-represented employees are not eligible for OPEB benefits 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.employees represented by Local 614 are not eligible for retiree health care benefits.
During the first quarter of 2017, in connection with the acquisition of Fitzpatrick,FitzPatrick, Exelon established a new qualified pension plan and a new OPEB plan and recorded a provisional obligation for Fitzpatrick employees based on information available at the merger date of $38 million and $11 million, respectively. As permitted by business combinations accountingauthoritative guidance, during the third quarter of 2017, Exelon updated those obligations based on a final valuation for FitzpatrickFitzPatrick employees as of the merger date of March 31, 2017. The updated obligations for pension and OPEB were $16 million and $17 million, respectively. Refer toSee Note 4 -— Mergers, Acquisitions and Dispositions for additional discussioninformation of the acquisition of FitzPatrick.
Defined Benefit Pension and Other Postretirement Benefits
During the first quarter of 2017,2018, Exelon received an updated valuation of its pension and other postretirement benefit obligationsOPEB to reflect actual census data as of January 1, 2017.2018. This valuation resulted in an increase to the pension obligationand OPEB obligations of $92$23 million and an increase to the other postretirement benefit obligation of $57 million.$14 million, respectively. Additionally, accumulated other comprehensive loss increaseddecreased by approximately $59$18 million (after tax),(after-tax) and regulatory assets increased by approximately $57 million and regulatory liabilities increased by approximately $4 million.$61 million and $1 million, respectively.
The majority of the 20172018 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.04%3.62%. The majority of the 20172018 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.58%6.60% for funded plans and a discount rate of 4.04%3.61%.

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 plans is capitalized within the Consolidated Balance Sheets. The following tables presenttable presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, 20172018 and 20162017.
 Pension Benefits
Three Months Ended September 30,		 Other Postretirement Benefits
Three Months Ended September 30,
 2018 
2017(a)
 2018 
2017(a)
Components of net periodic benefit cost:       
Service cost$100
 $98
 $28
 $26
Interest cost201
 211
 43
 45
Expected return on assets(312) (300) (43) (39)
Amortization of:       
Prior service cost (benefit)—
 (1) (47) (47)
Actuarial loss158
 152
 18
 15
Settlement charges—
 1
 —
 —
Net periodic benefit cost$147
 $161
 $(1) $—

Pension Benefits
Nine Months Ended September 30,		 Other Postretirement Benefits
Nine Months Ended September 30,
 2018 
2017(a)
 2018 
2017(a)
Components of net periodic benefit cost:

 

 

 

Service cost$303
 $290
 $84
 $79
Interest cost602
 632
 131
 136
Expected return on assets(939) (898) (130) (121)
Amortization of:       
Prior service cost (benefit)1
 —
 (140) (140)
Actuarial loss472
 455
 50
 46
Settlement charges1
 3
 —
 —
Net periodic benefit cost$440

$482

$(5)
$—
_________
(a)FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.

The amounts below represent Exelon's, Generation's, ComEd's, PECO's, BGE's, BSC's, PHI's, Pepco's, DPL's, ACE's, and PHI'sPHISCO's allocated portion of the pension and postretirement benefit plan costs. As a result of new pension guidance effective on January 1, 2018, certain balances have been reclassified on Exelon’s Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2017. The amounts below represent the Registrants’ as well as BSC's and PHISCO's pension and postretirement benefit plan net periodic benefit costs, prior to capitalization,costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment, net, for the predecessor period of January 1, 2016 to March 23, 2016.
 Pension Benefits
Three Months Ended September 30,		 Other Postretirement Benefits
Three Months Ended September 30,
 
2017(a)
 
2016(b)
 
2017(a)
 
2016(b)
Components of net periodic benefit cost:       
Service cost$98
 $92
 $26
 $27
Interest cost211
 215
 45
 47
Expected return on assets(300) (293) (39) (42)
Amortization of:       
Prior service (benefit) cost(1) 3
 (47) (48)
Actuarial loss152
 142
 15
 18
Settlement charges1
 —
 —
 —
Net periodic benefit cost$161
 $159
 $—
 $2
three and nine months ended September 30, 2018 and 2017, while the non-service cost components are included in Other, net and Regulatory assets for the three and nine months ended September 30, 2018 and in Other, net and Property, plant and equipment, net, for the three and nine months ended September 30, 2017. For the Registrants other than Exelon, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant and equipment, net on their consolidated financial statements for the three and nine months ended September 30, 2018 and 2017.

144
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

 Pension Benefits
Nine Months Ended September 30,		 Other Postretirement Benefits
Nine Months Ended September 30,
 
2017(a)
 
2016(b)
 
2017(a)
 
2016(b)
Components of net periodic benefit cost:

 

 

 

Service cost$290
 $262
 $79
 $80
Interest cost632
 616
 136
 138
Expected return on assets(898) (847) (121) (121)
Amortization of:       
Prior service cost (benefit)—
 10
 (140) (138)
Actuarial loss455
 411
 46
 47
Settlement charges3
 —
 —
 —
Net periodic benefit cost$482

$452

$—

$6
  Three Months Ended September 30, Nine Months Ended September 30,
Pension and Other Postretirement Benefit Costs 2018 2017 2018 2017
Exelon(a)(b)
 $145
 $161
 $435
 $482
Generation(b)
 50
 57
 151
 170
ComEd 45
 44
 133
 131
PECO 5
 7
 14
 21
BGE 15
 16
 44
 48
BSC(c)
 13
 13
 42
 40
PHI(a)
 17
 24
 51
 72
Pepco 3
 6
 10
 19
DPL 2
 3
 5
 10
ACE 3
 3
 10
 10
PHISCO(d)
 9
 12
 26
 33
_________
(a)Exelon reflects the consolidated pension and other postretirement benefit costs of Generation, ComEd, PECO, BGE, BSC, and PHI. PHI reflects the consolidated pension and other postretirement benefit costs of Pepco, DPL, ACE, and PHISCO.
(b)FitzPatrick net benefit costs are included for the period after acquisition.the acquisition date of March 31, 2017.
(b)PHI net periodic benefit costs for the period prior to the merger are not included in the table above.
 Predecessor
 PHI
 Pension Benefits Other Postretirement Benefits
 January 1, 2016 to March 23, 2016 January 1, 2016 to March 23, 2016
Components of net periodic benefit cost:   
Service cost$12
 $1
Interest cost26
 6
Expected return on assets(30) (5)
Amortization of:   
Prior service cost (benefit)—
 (3)
Actuarial loss14
 2
Net periodic benefit cost$22
 $1
The amounts below represent Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, DPL's, ACE's, BSC's and PHISCO's allocated portion of the pension and postretirement benefit plan costs, which were included in Property, plant and equipment within the respective Consolidated Balance Sheets and Operating and maintenance expense within the Consolidated Statement of Operations and Comprehensive Income during the three and nine months ended September 30, 2017 and 2016 and PHI's for the predecessor and successor periods of January 1, 2016 to March 23, 2016 and March 24, 2016 to September 30, 2016, respectively.
 Three Months Ended September 30, Nine Months Ended September 30,
Pension and Other Postretirement Benefit Costs2017 2016 2017 2016
Exelon$161
 $161
 $482
 $458
Generation(a)
57
 54
 170
 163
ComEd44
 41
 131
 124
PECO7
 8
 21
 25
BGE16
 17
 48
 51
BSC(b)
13
 13
 40
 37
Pepco(c)
6
 8
 19
 24
DPL(c)
3
 4
 10
 13
ACE(c)
3
 4
 10
 11
PHISCO(c)(d)
12
 12
 33
 33

145
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

 Successor  Predecessor
Pension and Other Postretirement Benefit CostsThree Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016  January 1, 2016 to March 23, 2016
PHI$24
 $28
 $72
 $58
  $23
_________
(a)FitzPatrick net benefit costs are included for the period after acquisition.
(b)(c)These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, ACE or ACEPHISCO amounts above.
(c)Pepco's, DPL's, ACE's and PHISCO's pension and postretirement benefit costs for the nine months ended September 30, 2016 include $7 million, $4 million, $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016.
(d)These amounts represent amounts billed to Pepco, DPL and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above.

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

Defined Contribution Savings Plans
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three and nine months ended September 30, 20172018 and 2016 and PHI's for the predecessor and successor periods of January 1, 2016 to March 23, 2016 and March 24, 2016 to September 30, 2016,2017, respectively.
Three Months Ended September 30, Nine Months Ended September 30, Three Months Ended September 30, Nine Months Ended
September 30,
Savings Plan Matching Contributions2017 2016 2017 2016 2018 2017 2018 2017
Exelon(b)$34

$51

$97

$107
 $44

$34

$126

$97
Generation(b)14
 31
 42
 56
 23
 14
 65
 42
ComEd9
 10
 24
 23
 8
 9
 23
 24
PECO3
 3
 7
 7
 2
 3
 7
 7
BGE3
 2
 7
 5
 2
 3
 5
 7
BSC(a)(c)
2
 2
 7
 9
 5
 2
 16
 7
Pepco(b)
1
 —
 3
 2
DPL(b)
1
 1
 2
 2
PHI(a)
 4
 3
 10
 10
Pepco 1
 1
 2
 3
DPL 1
 1
 2
 2
ACE—
 —
 1
 1
 1
 —
 2
 1
PHISCO(b)(c)
1
 2
 4
 5
PHISCO(d)
 1
 1
 4
 4
 Successor  Predecessor
Savings Plan Matching ContributionsThree Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016  January 1, 2016 to March 23, 2016
PHI$3
 $3
 $10
 $7
  $3
_________
(a)Exelon reflects the consolidated savings plan matching contributions of Generation, ComEd, PECO, BGE, BSC, and PHI. PHI reflects the consolidated savings plan matching contributions of Pepco, DPL, ACE, and PHISCO.
(b)FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.
(c)These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, ACE or ACEPHISCO amounts above.
(b)Pepco's, DPL's and PHISCO's matching contributions for the nine months ended September 30, 2016 include $1 million, $1 million, and $1 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016, which is not included in Exelon’s matching contributions for the nine months ended September 30, 2016.
(c)(d)These amounts represent amounts billed to Pepco DPL, and ACEDPL through intercompany allocations. These amounts are not included in Pepco DPL, or ACEDPL amounts above.
15.    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

146
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

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 three and nine months ended September 30, 2017 and 2016, Exelon, Generation, ComEd, PHI, Pepco, DPL, and ACE recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income.
       Successor      
 Exelon 
Generation(a)
 
ComEd(a)
 PHI 
Pepco(a)
 
DPL(a)
 
ACE(a)
Three Months Ended             
September 30, 2017$1
 $—
 $—
 $1
 $1
 $—
 $—
September 30, 20168
 7
 —
 1
 —
 —
 —
              
Nine Months Ended             
September 30, 2017$10
 $4
 $2
 $4
 $2
 $1
 $1
September 30, 201612
 10
 1
 1
 —
 —
 —
_________
(a)The amounts above for Generation include $2 million for amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2017 and $1 million and $2 million for the three and nine months ended September 30, 2016, respectively. The amounts above for ComEd include $1 million for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2016. The amounts above for PHI include less than $1 million and $1 million billed by BSC through intercompany allocations for the three and nine months ended September 30, 2017, respectively, and $1 million for the three and nine months ended September 30, 2016. Amounts billed by PHISCO to Pepco were $1 million and $2 million for the three and nine months ended September 30, 2017, respectively. Amounts billed by PHISCO to DPL and ACE were $1 million, each, for the nine months ended September 30, 2017. Pepco, DPL and ACE did not have any ongoing severance plans for the three and nine months ended September 30, 2016.
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.
For the three and nine months ended September 30, 2017 and 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:
 Exelon Generation ComEd PECO BGE
Three Months Ended         
September 30, 2017(a)
$7
 $7
 $—
 $—
 $—
September 30, 2016(b)
1
 1
 —
 —
 —
          
Nine Months Ended         
September 30, 2017(a)
$6
 $6
 $—
 $—
 $—
September 30, 2016(b)
18
 13
 3
 1
 1
_________
(a)Amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2017 were immaterial.
(b)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 nine months ended September 30, 2016.

147
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Early Plant Retirement-Related Severance (Exelon and Generation)
As a result of the Three Mile Island plant retirement decision, Exelon and Generation will incur certain employee-related costs, including severance benefit costs. Severance costs will be provided to management employees that are eligible under Exelon’s severance policy, to the extent that those employees are not redeployed to other locations. In June 2017, Exelon and Generation recognized severance costs of $17 million related to expected management employee severances resulting from the plant retirements within Operating and maintenance expense in their Consolidated Statements of Operation and Comprehensive Income. Approximately half of the employees at this location fall under a collective bargaining union agreement and are not eligible for severance benefits under an existing plan. The union and Exelon will negotiate terms of any severance benefits. If severance benefits are successfully negotiated, the amounts will be accrued as a one-time employee termination benefit once the established plan is communicated to employees. The final amount of the severance cost will ultimately depend on the specific employees severed. See Note 7 - Early Nuclear Plant Retirements for additional information regarding the announced early retirement of TMI.
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 three and nine months ended September 30, 2017 and the three months ended September 30, 2016, the PHI Merger severance costs were immaterial. For the nine months ended September 30, 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:
           Successor      
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Nine Months Ended September 30, 2016                 
Severance costs(a)
$55
 $9
 $2
 $1
 $1
 $42
 $20
 $12
 $10
_________
(a)The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $8 million, $2 million, $1 million, $1 million, $19 million, $11 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the nine months ended September 30, 2016.
PHI, Pepco, DPL and ACE record regulatory assets for merger related integration costs which include a portion of the severance costs in the table above related to the PHI Merger. These regulatory assets are either currently being recovered in rates or are deemed probable of recovery in future rates. See Note 5 - Regulatory Matters for further information.
Severance Liability
Amounts included in the table below represent the severance liability recorded for the severance plans above for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:
           Successor      
Severance LiabilityExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2016$88
 $36
 $3
 $—
 $—
 $29
 $—
 $—
 $—
Severance charges(a)
33
 25
 1
 —
 —
 3
 —
 —
 —
Payments(24) (7) (1) —
 —
 (11) —
 —
 —
Balance at September 30, 2017$97
 $54
 $3
 $—
 $—
 $21
 $—
 $—
 $—
_________
(a)Includes salary continuance and health and welfare severance benefits.

148
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

16.15. Changes in Accumulated Other Comprehensive Income (Exelon, Generation PECO and PHI)PECO)
The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the nine months ended September 30, 20172018 and 2016:2017:
Nine Months Ended September 30, 2017Gains 
and
(losses) 
on Cash Flow Hedges		 
Unrealized
Gains and
(losses) on
Marketable
Securities
 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items
 
Foreign
Currency
Items
 
AOCI of
Equity
Investments
 Total
Nine Months Ended September 30, 2018Gains (Losses) on Cash Flow Hedges Unrealized gains (losses) on Marketable Securities 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates
 Total
Exelon(a)
                      
Beginning balance$(17) $4
 $(2,610) $(30) $(7) $(2,660)$(14) $10
 $(2,998)
(d) 
$(23) $(1) $(3,026)
OCI before reclassifications2
 2
 (55) 7
 7
 (37)11
 —
 22
 (4) 1
 30
Amounts reclassified from AOCI(b)
3
 —
 105
 —
 —
 108
1
 —
 136
 —
 —
 137
Net current-period OCI5
 2
 50
 7
 7
 71
12
 —
 158
 (4) 1
 167
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 (10)
(c) 
—
 —
 —
 (10)
Ending balance$(12) $6
 $(2,560) $(23) $—
 $(2,589)$(2) $—
 $(2,840) $(27) $—
 $(2,869)
Generation(a)
          

          

Beginning balance$(19) $2
 $—
 $(30) $(7) $(54)$(16) $3
 $—
 $(23) $(1) $(37)
OCI before reclassifications2
 —
 —
 7
 6
 15
11
 —
 —
 (4) 1
 8
Amounts reclassified from AOCI(b)
3
 —
 —
 —
 —
 3
1
 —
 —
 —
 —
 1
Net current-period OCI5
 —
 —
 7
 6
 18
12
 —
 —
 (4) 1
 9
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 (3)
(c) 
—
 —
 —
 (3)
Ending balance$(14) $2
 $—
 $(23) $(1) $(36)$(4) $—
 $—
 $(27) $—
 $(31)
PECO(a)
          
          
Beginning balance$—
 $1
 $—
 $—
 $—
 $1
$—
 $1
 $—
 $—
 $—
 $1
OCI before reclassifications—
 —
 —
 —
 —
 —
—
 —
 —
 —
 —
 —
Amounts reclassified from AOCI(b)
—
 —
 —
 —
 —
 —
—
 —
 —
 —
 —
 —
Net current-period OCI—
 —
 —
 —
 —
 —
—
 —
 —
 —
 —
 —
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 (1)
(c) 
—
 —
 —
 (1)
Ending balance$—
 $1
 $—
 $—
 $—
 $1
$—
 $—
 $—
 $—
 $—
 $—

149
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Nine Months Ended September 30, 2016Gains 
and
(losses) 
on Cash Flow Hedges		 
Unrealized
Gains and
(losses) on
Marketable
Securities
 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items
 
Foreign
Currency
Items
 
AOCI of
Equity
Investments
 Total
Nine Months Ended September 30, 2017Gains (Losses) on Cash Flow Hedges Unrealized gains (losses) on Marketable Securities 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates
 Total
Exelon(a)
                      
Beginning balance$(19) $3
 $(2,565) $(40) $(3) $(2,624)$(17) $4
 $(2,610) $(30) $(7) $(2,660)
OCI before reclassifications(9) —
 (2) 3
 (5) (13)2
 2
 (55) 7
 7
 (37)
Amounts reclassified from AOCI(b)
5
 —
 104
 5
 —
 114
3
 —
 105
 —
 —
 108
Net current-period OCI(4) —
 102
 8
 (5) 101
5
 2
 50
 7
 7
 71
Ending balance$(23) $3
 $(2,463) $(32) $(8) $(2,523)$(12) $6
 $(2,560) $(23) $—
 $(2,589)
Generation(a)
          
          
Beginning balance$(21) $1
 $—
 $(40) $(3) $(63)$(19) $2
 $—
 $(30) $(7) $(54)
OCI before reclassifications(8) 1
 —
 3
 1
 (3)2
 —
 —
 7
 6
 15
Amounts reclassified from AOCI(b)
5
 —
 —
 5
 —
 10
3
 —
 —
 —
 —
 3
Net current-period OCI(3) 1
 —
 8
 1
 7
5
 —
 —
 7
 6
 18
Ending balance$(24) $2
 $—
 $(32) $(2) $(56)$(14) $2
 $—
 $(23) $(1) $(36)
PECO(a)
          

          

Beginning balance$—
 $1
 $—
 $—
 $—
 $1
$—
 $1
 $—
 $—
 $—
 $1
OCI before reclassifications—
 —
 —
 —
 —
 —
—
 —
 —
 —
 —
 —
Amounts reclassified from AOCI(b)
—
 —
 —
 —
 —
 —
—
 —
 —
 —
 —
 —
Net current-period OCI—
 —
 —
 —
 —
 —
—
 —
 —
 —
 —
 —
Ending balance$—
 $1
 $—
 $—
 $—
 $1
$—
 $1
 $—
 $—
 $—
 $1
PHI Predecessor(a)
           
Beginning balance January 1, 2016$(8) $—
 $(28) $—
 $—
 $(36)
OCI before reclassifications—
 —
 —
 —
 —
 —
Amounts reclassified from AOCI(b)
—
 —
 1
 —
 —
 1
Net current-period OCI—
 —
 1
 —
 —
 1
Ending balance March 23, 2016(c)
$(8) $—
 $(27) $—
 $—
 $(35)
_________
(a)All amounts are net of tax and noncontrolling interest.interests. Amounts in parenthesis represent a decrease in AOCI.
(b)See next tables for details about these reclassifications.
(c)As a resultExelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million, $3 million and $1 million for Exelon, Generation and PECO, respectively. The amounts reclassified related to Rabbi Trusts. See Note 2 — New Accounting Standards for additional information.
(d)Exelon early adopted the PHI Merger, the PHI predecessor balances at March 23, 2016 were reducednew standard Reclassification of Certain Tax Effects from AOCI. The standard was adopted retrospectively as of December 31, 2017, which resulted in an increase to zero on March 24, 2016 dueExelon’s Retained earnings and Accumulated other comprehensive loss of $539 million, primarily related to purchase accounting adjustments applied to PHI.deferred income taxes associated with Exelon’s pension and OPEB obligations. See Note 2 — New Accounting Standards for additional information.

150
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

ComEd, PECO, BGE, PHI, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the three and nine months ended September 30, 20172018 and 2016.2017. The following tables present amounts reclassified out of AOCI to Net income for Exelon Generation and PHIGeneration during the three and nine months ended September 30, 20172018 and 2016.2017.
Three Months Ended September 30, 20172018
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
  Exelon Generation  
Gains (losses) on cash flow hedges      
Other cash flow hedges $2
 $2
 Interest expense
Total before tax 2
 2
  
Tax benefit (1) (1)  
Net of tax $1
 $1
 Comprehensive income
       
Amortization of pension and other postretirement benefit plan items      
Prior service costs(b)
 $23
 $—
  
Actuarial losses(b)
 (81) —
  
Total before tax (58) —
  
Tax benefit 23
 —
  
Net of tax $(35) $—
  
       
Total Reclassifications for the period $(34) $1
 Comprehensive income
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
  Exelon Generation  
Gains (Losses) on cash flow hedges      
Other cash flow hedges $—
 $—
 Interest expense
  —
 —
 Total before tax
  —
 —
 Tax benefit
  $—
 $—
 Net of tax
       
Amortization of pension and other postretirement benefit plan items      
Prior service costs(b)
 $23
 $—
  
Actuarial losses(b)
 (83) —
  
  (60) —
 Total before tax
  15
 —
 Tax benefit
  $(45) $—
 Net of tax
       
Total Reclassifications $(45) $—
 Net of tax
Nine Months Ended September 30, 20172018
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
       
  Exelon Generation  
Gains and (losses) on cash flow hedges      
Other cash flow hedges $(5) $(5) Interest expense
Total before tax (5)
(5)
 
Tax benefit 2
 2
  
Net of tax $(3) $(3) Comprehensive income
       
Amortization of pension and other postretirement benefit plan items      
Prior service costs(b)
 $69
 $—
  
Actuarial losses(b)
 (243) —
  
Total before tax (174) —
  
Tax benefit 69
 —
  
Net of tax $(105) $—
  
       
Total Reclassifications $(108) $(3) Comprehensive income
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
  Exelon Generation  
Gains (Losses) on cash flow hedges      
Other cash flow hedges $(1) $(1) Interest expense
  (1)
(1)
Total before tax
  —
 —
 Tax benefit
  $(1) $(1) Net of tax
       
Amortization of pension and other postretirement benefit plan items      
Prior service costs(b)
 $68
 $—
  
Actuarial losses(b)
 (251) —
  
  (183) —
 Total before tax
  47
 —
 Tax benefit
  $(136) $—
 Net of tax
       
Total Reclassifications $(137) $(1) Net of tax

151
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Three Months Ended September 30, 20162017
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
       
  Exelon Generation  
Gains and (losses) on cash flow hedges      
Other cash flow hedges $(3) $(3) Interest expense
Total before tax (3) (3)  
Tax expense 1
 1
  
Net of tax $(2) $(2) Comprehensive income
       
Amortization of pension and other postretirement benefit plan items      
Prior service costs(b)
 $19
 $—
  
Actuarial losses(b)
 (76) —
  
Total before tax (57) —
  
Tax benefit 22
 —
  
Net of tax $(35) $—
  
       
Gains and (losses) on foreign currency translation      
Other $(5) $(5) Other Income and (deductions)
Total before tax (5) (5)  
Tax expense —
 —
  
Net of tax $(5) $(5) Comprehensive income
       
Total Reclassifications for the period $(42) $(7) Comprehensive income

152
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
  Exelon Generation  
Gains (Losses) on cash flow hedges      
Other cash flow hedges $2
 $2
 Interest expense
  2
 2
 Total before tax
  (1) (1) Tax expense
  $1
 $1
 Net of tax
       
Amortization of pension and other postretirement benefit plan items      
Prior service costs(b)
 $23
 $—
  
Actuarial losses(b)
 (81) —
  
  (58) —
 Total before tax
  23
 —
 Tax benefit
  $(35) $—
 Net of tax
       
Total Reclassifications $(34) $1
 Net of tax
Nine Months Ended September 30, 20162017
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
      Predecessor  
  Exelon Generation PHI  
Gains and (losses) on cash flow hedges        
Other cash flow hedges $(8) $(8) $—
 Interest expense
Total before tax (8)
(8)
—
  
Tax benefit 3
 3
 —
  
Net of tax $(5) $(5) $—
 Comprehensive income
         
Amortization of pension and other postretirement benefit plan items        
Prior service costs(b)
 $57
 $—
 $—
  
Actuarial losses(b)
 (227) —
 (1)  
Total before tax (170) —
 (1)  
Tax benefit 66
 —
 —
  
Net of tax $(104) $—
 $(1)  
         
Gains and (losses) on foreign currency translation        
Other $(5) $(5) $—
 Other income and (deductions)
Total before tax (5) (5) —
  
Tax expense —
 —
 —
  
Net of tax $(5) $(5) $—
  
         
Total Reclassifications $(114) $(10) $(1) Comprehensive income
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
  Exelon Generation  
Gains (Losses) on cash flow hedges      
Other cash flow hedges $(5) $(5) Interest expense
  (5)
(5)
Total before tax
  2
 2
 Tax benefit
  $(3) $(3) Net of tax
       
Amortization of pension and other postretirement benefit plan items      
Prior service costs(b)
 $69
 $—
  
Actuarial losses(b)
 (243) —
  
  (174) —
 Total before tax
  69
 —
 Tax benefit
  $(105) $—
 Net of tax
       
Total Reclassifications $(108) $(3) Net of tax
_________
(a)Amounts in parenthesis represent a decrease in net income.AOCI.
(b)This AOCI component is included in the computation of net periodic pension and OPEB cost (see Note 14 — Retirement Benefits for additional details)information).

153
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

The following table presents income tax expense (benefit)benefit (expense) allocated to each component of other comprehensive income (loss) during the three and nine months ended September 30, 20172018 and 2016:
 Three Months Ended September 30, Nine Months Ended 
 September 30,
 2017 2016 2017 2016
Exelon       
Pension and non-pension postretirement benefit plans:       
Prior service benefit reclassified to periodic benefit cost$9
 $7
 $27
 $22
Actuarial loss reclassified to periodic benefit cost(32) (29) (96) (88)
Pension and non-pension postretirement benefit plans valuation adjustment—
 1
 2
 1
Change in unrealized (loss)/gain on cash flow hedges—
 (1) (3) 3
Change in unrealized (loss)/gain on equity investments1
 —
 (2) 3
Change in unrealized (loss)/gain on marketable securities—
 (1) (2) (1)
Total$(22) $(23) $(74) $(60)
        
Generation       
Change in unrealized (loss)/gain on cash flow hedges$—
 $(2) $(3) $1
Change in unrealized (loss)/gain on equity investments—
 —
 (2) 3
Change in unrealized gain on marketable securities—
 —
 (1) —
Total$—
 $(2) $(6) $4
2017:
Predecessor
PHIJanuary 1, 2016 to March 23, 2016
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost$—
 Three Months Ended September 30, Nine Months Ended
September 30,
 2018 2017 2018 2017
Exelon       
Pension and non-pension postretirement benefit plans:       
Prior service benefit reclassified to periodic benefit cost$6
 $9
 $18
 $27
Actuarial loss reclassified to periodic benefit cost(21) (32) (65) (96)
Pension and non-pension postretirement benefit plans valuation adjustment(2) —
 (8) 2
Change in unrealized gains on cash flow hedges—
 —
 (5) (3)
Change in unrealized gains (losses) on investments in unconsolidated affiliates—
 1
 (1) (2)
Change in unrealized gains on marketable securities—
 —
 —
 (2)
Total$(17) $(22) $(61) $(74)
        
Generation       
Change in unrealized gains on cash flow hedges$—
 $—
 $(4) $(3)
Change in unrealized gains on investments in unconsolidated affiliates—
 —
 (1) (2)
Change in unrealized gains on marketable securities—
 —
 —
 (1)
Total$—
 $—
 $(5) $(6)
17.16. Earnings Per Share and Equity (Exelon)
Earnings per Share
DilutedBasic earnings per share is calculatedcomputed by dividing Netnet income attributable to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income attributable to common shareholders by the weighted average number of common stockshares outstanding, including shares to be issued upon exercisethe effect of issuing common stock assuming (i) stock options are exercised, and (ii) performance share awards and restricted stock outstandingawards are fully vested under Exelon’s LTIPs considered to be commonthe treasury stock equivalents. method.
The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock awards on the weighted average number of shares outstanding used in calculating diluted earnings per share:
Three Months Ended September 30,
Nine Months Ended September 30,Three Months Ended September 30,
Nine Months Ended September 30,
2017
2016
2017
20162018
2017
2018
2017
Exelon              
Net income attributable to common shareholders$824
 $490
 $1,899
 $930
$733
 $823
 $1,858
 $1,907
Weighted average common shares outstanding — basic962
 925
 941
 924
968
 962
 967
 941
Assumed exercise and/or distributions of stock-based awards3
 2
 2
 2
2
 3
 2
 2
Weighted average common shares outstanding — diluted965
 927
 943
 926
970
 965
 969
 943

154
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 2 million and 3 million for the three and nine months ended September 30, 2018, respectively, and 7 million and 9 million for the three and nine months ended September 30, 2017, respectively, and 11 million and 12 million for the three and nine months ended September 30, 2016, respectively. 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 three and nine months ended September 30, 2018 and 2017. 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 was less than 1 million for the three and nine months ended September 30, 2016. Refer toSee Note 2019 — Shareholders' Equity of the Exelon 20162017 Form 10-K for furtheradditional information regarding the equity units.
On June 1, 2017, Exelon settled the forward purchase contract, which was a component of the June 2014 equity units, through the issuance of approximately 33Under share repurchase programs, 2 million shares of Exelon common stock from treasury stock. The issuance of shares on June 1, 2017, triggered full dilution in the EPS calculation, which prior to settlement were included in the calculation of diluted EPS using the treasury stock method.
Prior to the June 2017 issuance Exelon had approximately 35 million shares ofare held as treasury stock with a cost of $2.3 billion. After issuance, Exelon has approximately 2$123 million sharesas of Treasury stock remaining, at a historical cost of $123 million. In 2008, Exelon management decided to defer indefinitely any share repurchases.September 30, 2018.
18.17. Commitments and Contingencies (All Registrants)
The following is an update to the current status of commitments and contingencies set forth in Note 2423 of the Exelon 20162017 Form 10-K .10-K. See Note 4 -— Mergers, Acquisitions and Dispositions of the Exelon 2017 Form 10-K for further discussionadditional information on the PHI Merger commitments.
Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL and ACE)
The merger of Exelon and PHI was approved in Delaware, New Jersey, Maryland and the District of Columbia. Exelon and PHI agreed to certain commitments including where applicable: customer rate credits, funding for energy efficiency and delivery system modernization programs, a green sustainability fund, workforce development initiatives, charitable contributions, renewable generation and other required commitments. In addition, the orders approving the merger in Delaware, New Jersey, and Maryland include a “most favored nation” provision which, generally, requires allocation of merger benefits proportionally across all the jurisdictions.
The following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the acquisition date and the remaining obligations as of September 30, 2018:
DescriptionExpected Payment Period Exelon PHI Pepco DPL ACE
Rate credits2016 - 2021 $259
 $259
 $91
 $67
 $101
Energy efficiency2016 - 2021 122
 —
 —
 —
 —
Charitable contributions2016 - 2026 50
 50
 28
 12
 10
Delivery system modernizationQ2 2017 22
 —
 —
 —
 —
Green sustainability fundQ2 2017 14
 —
 —
 —
 —
Workforce development2016 - 2020 17
 —
 —
 —
 —
Other  29
 6
 1
 5
 —
Total commitments  $513
 $315
 $120
 $84
 $111
Remaining commitments  $138
 $94
 $75
 $12
 $7
In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new generation in Maryland, District of Columbia, and Delaware, 27 MWs of which are expected to be completed in 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

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

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.
Constellation Merger Commitments (Exelon and Generation)
In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion.
The direct investment includes the construction of a new 21-story headquarters building in Baltimore for Generation’s competitive energy business that was substantially complete in November 2016 and is now occupied by approximately 1,500 Exelon employees.  Generation’s investment includes leasehold improvements that are not expected to exceed $110 million.  In addition, Generation entered into a 20 year operating lease as the primary lessee of the building.  Refer to Note 24 - Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements in the Exelon 2016 Form 10-K for additional information regarding Generation’s future minimum lease payments.
The direct investment commitment also includes $450 million to $500 million relating to Exelon and Generation’s developmentdevelop or assistanceassist 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. generation. Exelon and Generation have incurred $457$458 million towards satisfying the commitment for new generation development in the stateState of Maryland, with approximately 220 MW of the new generation commencing with commercialin operations to date and an additional 10 MW of this commitment satisfied through a liquidated damages payment made in the fourth quarter of 2016. Additionally, during the fourth quarter of 2016, given continued declines in projected energy and capacity prices, Generation terminated rights to certain development projects originally intended to meet itsThe remaining 55 MW commitment amount. The commitment will now most likelyis expected to be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by Generation constructing renewable generating assets. As a result, Exelon and Generation recorded a pre-tax$50 million loss contingency in Operating and maintenance expense inas of September 30, 2018 Exelon’s and Generation’s Consolidated StatementsBalance Sheets include a $50 million liability within Deferred credits and other liabilities for this remaining commitment, to be paid on or before January 15, 2023 unless the period is extended by consent of OperationsExelon and Comprehensive Income for the year ended December 31, 2016.

155
TableState of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Equity InvestmentMaryland. See Note 23 - Commitments (Exelon and Generation)
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 needsContingencies of the planned operations ofExelon 2017 Form 10-K for additional information regarding the associated companies. As of September 30, 2017, Generation’s estimated commitments relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:
 Total
2017 (remainder of year)$12
20186
20193
Total$21
Constellation Merger Commitments.
Commercial Commitments (All Registrants)
The Registrants’ commercial commitments as of September 30, 2017,2018, representing commitments potentially triggered by future events were as follows:
          Successor      
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Letters of credit (non-debt)(a)
$1,276
 $1,193
 $14
 $22
 $2
 $1
 $1
 $—
 $—
 $1,584
 $1,565
 $2
 $—
 $3
 $4
 $4
 $—
 $—
Surety bonds(b)
1,206
 1,079
 20
 40
 11
 21
 13
 4
 4
 1,402
 1,201
 9
 9
 25
 65
 32
 4
 3
Financing trust guarantees378
 —
 200
 178
 —
 —
 —
 —
 —
 378
 —
 200
 178
 —
 —
 —
 —
 —
Guaranteed lease residual values(c)
19
 —
 —
 —
 —
 19
 6
 7
 5
 22
 —
 —
 —
 —
 22
 7
 9
 6
Total commercial commitments$2,879
 $2,272
 $234
 $240
 $13

$41
 $20
 $11
 $9
 $3,386
 $2,766
 $211
 $187
 $28

$91
 $43
 $13
 $9
_________
(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. Includes letters of credits issued under credit facility agreements arranged at minority and community banks and nonrecourse debt letters of credits.
(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 $49$60 million, $14$17 million of which is a guarantee by Pepco, $19$25 million by DPL and $13$17 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.
Nuclear Insurance (Exelon and Generation)
Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.

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

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 September 30, 2017,2018, the current liability limit per incident is $13.4$13.1 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactorsreactors. Changes to account for the effects of inflation occur 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$12.6 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $2.8 billion, including CENG's related liability, however any amounts payable under this secondary layer would be capped at $420 million per year.

156
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.4$13.1 billion limit for a single incident.
As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 52 — Investment in Constellation Energy Nuclear Group, LLCVariable Interest Entities of the Exelon 20162017 Form 10-K 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. In March 2018, NEIL declared a supplemental distribution. Generation's portion of the supplemental distribution declared by NEIL was $31 million and was recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income for the nine months ended September 30, 2018.
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 $360$345 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.
NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing

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

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.cash flows.
Environmental IssuesRemediation Matters
General (All Registrants)
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, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial conditions, results of operations and cash flows.
MGP Sites (Exelon, ComEd, PECO, BGE, PHI and DPL)
ComEd, PECO, BGE and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
ComEd has identified 42 sites, 1920 of which the remediation hashave been completedremediated and approved by the Illinois EPA or the U.S. EPA and 2322 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 2022.2023.
PECO has identified 26 sites, 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remainingrequirements and 9 sitesthat are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.

BGE has identified 13 sites, 9 of which have been remediated and approved by the MDE and 4 that require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2019.
157
TableDPL has identified 3 sites, for 2 of Contentswhich remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control.

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

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 of the gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The required costs at these two sites are not considered material.In May 2017, BGE completed the additional work requested by MDE.  All the sample testing produced results that were below the cleanup action level established by MDE and no further investigation is required.  For more information, see the discussion of the Riverside site below.
DPL has identified 3 sites, 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control. The remaining site is under study and the required cost at the site is not consideredexpected to be material.
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. ComEd and PECO have recorded regulatory assets for the recovery of these costs. See Note 5 — 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.
As of September 30, 2017 and December 31, 2016, 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:
September 30, 2017
Total Environmental
Investigation and
Remediation Reserve
 
Portion of Total Related to
MGP Investigation and
Remediation
Exelon$429

$327
Generation76
 —
ComEd294
 293
PECO33
 32
BGE3
 2
PHI (Successor)23

—
Pepco21
 —
DPL1
 —
ACE1
 —
December 31, 2016
Total Environmental
Investigation and
Remediation Reserve
 
Portion of Total Related to
MGP Investigation and
Remediation
Exelon$429

$325
Generation72
 —
ComEd292
 291
PECO33
 31
BGE2
 2
PHI (Successor)30

1
Pepco27
 —
DPL2
 1
ACE1
 —
The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and

158
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. See Note 6 — Regulatory Matters for additional information regarding the associated regulatory assets. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
During the third quarter of 2017, ComEd, PECO, BGE and PHI2018, the Utility Registrants completed an annual study of their future estimated MGP remediation requirements. The study resulted in a $13 million and $2$48 million increase to the environmental liabilitiesliability and related regulatory assetsasset for ComEd. The increase was primarily due to a revised closure strategy at one site, which resulted in an increase in the excavation area and depth of impacted soils from the site. The study did not result in a material change to the environmental liability for PECO, BGE, Pepco, DPL and ACE.
As of September 30, 2018 and December 31, 2017, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
September 30, 2018
Total environmental
investigation and
remediation reserve
 
Portion of total related to
MGP investigation and
remediation
Exelon$486

$352
Generation102
 —
ComEd323
 321
PECO28
 27
BGE6
 4
PHI27

—
Pepco25
 —
DPL1
 —
ACE1
 —

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

December 31, 2017
Total environmental
investigation and
remediation reserve
 
Portion of total related to
MGP investigation and
remediation
Exelon$466

$315
Generation117
 —
ComEd285
 283
PECO30
 28
BGE5
 4
PHI29

—
Pepco27
 —
DPL1
 —
ACE1
 —
Solid and Hazardous Waste
Cotter Corporation (Exelon and Generation)
The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the EPA issued a Record of Decision (ROD) approving a landfill cover remediation approach. Generation had previously recorded an estimated liability for its anticipated share of a landfill cover remedy that was estimated to cost approximately $90 million in total. 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 PECO, respectively,groundwater and soil sampling as part of the supplemental feasibility study. This further analysis was focused on a partial excavation remedial option. The PRPs provided the final Remedial Investigation and Feasibility Study (RI/FS) to the EPA in January 2018, which formed the basis for EPA’s final remedy selection, as discussed below. There are currently three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.
On September 27, 2018 the EPA issued its ROD Amendment for the selection of the final remedy for the West Lake Landfill Superfund site. The ROD modifies the EPA’s previously proposed plan for partial excavation of the radiological materials by reducing the depths of the excavation. The ROD also allows for variation in depths of excavation depending on radiological concentrations. The EPA estimates that the ROD will result in a reduction of both radiological and non-radiological waste excavated, with corresponding reductions in the cost and schedule for the remedy. The next step is the negotiation of a Consent Agreement by the EPA with the PRPs to implement the ROD, a process that is expected to be completed in the first quarter of 2020. The estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost for the entire remediation effort. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement

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

the required remediation remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Generation’s associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial conditions, results of operations and cash flows.
On January 16, 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater RI/FS and reimbursement of EPA’s oversight costs. The purposes of this new RI/FS are to define the nature and extent of any groundwater contamination from the West Lake Landfill site, determine the potential risk posed to human health and the environment, and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS for West Lake to be approximately $20 million and Generation has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities will be required and cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future 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, and the work is expected to be completed in 2018. The second action involved EPA's public statement that it will require the PRPs to construct a barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Generation believes that the requirement to build a barrier wall is remote in light of other technologies that have been employed by the adjacent landfill owner. Finally, one of the other PRPs, the landfill owner and operator of the adjacent landfill, has indicated that it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial conditions, results of operations and cash flows.
On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million from all PRPs. The DOJ and the PRPs agreed to toll the statute of limitations until August 2019 so that settlement discussions could proceed. Generation has determined that a loss associated with this matter is probable under its

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

indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above.
Commencing in February 2012, a number of lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, as well as Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer or other serious illness due to Cotter's negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs are asserting public liability claims under the Price-Anderson Act. Their state law claims for negligence, strict liability, emotional distress, and medical monitoring have been dismissed. In the event of a finding of liability against Cotter, it is probable that Generation would be financially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed a number of the lawsuits as untimely, which has been upheld on appeal. Cotter and the remaining plaintiffs have engaged in settlement discussions pursuant to court-ordered mediation. During the second quarter of 2018, Generation determined a loss was probable based on the advancement of settlement proceedings and recorded an immaterial liability.
Benning Road Site (Exelon, Generation, PHI and Pepco)
In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a Remediation Investigation (RI)/ Feasibility Study (FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The Consent Decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. Pursuant to Exelon's March 23, 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation.
Since 2013, Pepco and Pepco Energy Services (now Generation) have been performing RI work and have submitted multiple draft RI reports to the DOEE. Once the RI work is completed, Pepco and Generation will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Generation will then proceed to develop an FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the RI and FS, and approval by the DOEE, by May 6, 2019.
Upon DOEE’s approval of the final RI and FS Reports, Pepco and Generation will have satisfied their obligations under the Consent Decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.
PHI, Pepco and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI and Pepco)
Contemporaneous with the Benning RI/FS being performed by Pepco and Generation, DOEE and certain federal agencies have been conducting a separate RI/FS focused on the entire tidal reach of the

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

Anacostia River extending from just north of the Maryland-D.C. boundary line to the confluence of the Anacostia and Potomac Rivers. In March 2016, DOEE released a draft of the river-wide RI Report for public review and comment. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a “Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning RI/FS. Pepco responded that it will participate in the Consultative Working Group, but its participation is not an acceptance of any financial responsibility beyond the work that will be performed at the Benning Road site described above. In April 2018, DOEE released a draft remedial investigation report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing. Pepco continues outreach efforts as appropriate to the agencies, governmental officials, community organizations and other key stakeholders. In May 2018 the District of Columbia Council extended the deadline for completion of the Record of Decision from June 30, 2018 until December 31, 2019. An appropriate liability for Pepco’s share of investigation costs has been accrued and is included in the table above. Although Pepco has determined that it is probable that costs for remediation will be incurred, Pepco cannot estimate the reasonably possible range of loss at this time and no changeliability has been accrued for those future costs. A draft Feasibility Study of potential remedies and their estimated costs is being prepared by the agencies and is expected to be released in early 2019, at BGEwhich time Pepco will likely be in a better position to estimate the range of loss.
In addition to the activities associated with the remedial process outlined above, there is a complementary statutory program that requires an assessment to determine if any natural resources have been damaged as a result of the contamination that is being remediated, and, if so, that a plan be developed by the federal, state and local Trustees responsible for those resources to restore them to their condition before injury from the environmental contaminants. If natural resources are not restored, then compensation for the injury can be sought from the party responsible for the release of the contaminants. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also effectively restore habitat. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process it cannot reasonably estimate the range of loss. 
Conectiv Energy Wholesale Power Generation Sites (Exelon, Generation, and PHI)
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 indemnified Calpine for any ISRA compliance remediation costs in excess of $10 million. PHI estimated 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 recorded a liability for its share of the estimated clean-up costs. Pursuant to Exelon’s March 2016 acquisition of PHI, the Conectiv Energy legal entity was transferred to Generation and the liability for PHI's share of the estimated clean-up costs was also transferred to Generation and is included in the table above as a liability of Generation. The responsibility to indemnify Calpine is shared by PHI and Generation.

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

Brandywine Fly Ash Disposal Site (Exelon, PHI and Pepco)
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.
Pepco has determined that a loss associated with this matter is probable and has recorded an estimated liability, which is included in the table above. Pepco believes that the costs incurred in this matter may be recoverable from NRG under the 2000 sale agreement but has not recorded an associated receivable for any potential recovery.
Litigation and Regulatory Matters
PHI Merger (Exelon and PHI)
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 Exelon and PHI merger. The Circuit Court judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, CCAN and Public Citizen, Inc. On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed notices of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment that the MDPSC did not err in approving the merger. The OPC and Sierra Club filed petitions seeking further review in the Court of Appeals of Maryland, which is the highest court in Maryland. On June 21, 2017, the Court of Appeals granted discretionary review of the January 27, 2017 decision by the Maryland Court of Special Appeals. The Maryland Court of Appeals will review the OPC argument that the MDPSC did not properly consider the acquisition premium paid to PHI shareholders under Maryland’s merger approval standard and the Sierra Club’s argument that the merger would harm the renewable and distributed generation markets. The two lower courts examining these issues rejected these arguments, which Exelon believes are without merit. All briefs have been filed and oral arguments were presented to the court on October 10, 2017. On August 29, 2018, the Maryland Court of Appeals affirmed the MDPSC's May 2015 Order approving the merger of Exelon and PHI. This concluded the final legal challenge to the merger of Exelon and PHI.
Asbestos Personal Injury Claims (Exelon, Generation, PECO and ComEd)
Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.
At September 30, 2018 and December 31, 2017, Generation had recorded estimated liabilities of approximately $80 million and $78 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2018, approximately $24 million of this amount related to 241 open claims presented to Generation, while the remaining $56 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.

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

There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases could have a material unfavorable impact on Exelon's, Generation's and PECO's financial conditions, results of operations and cash flows.
City of Everett Tax Increment Financing Agreement (Exelon and Generation)
On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. Generation vigorously contested the City’s claims before the EACC and will continue to do so in the Massachusetts Superior Court proceeding. Generation continues to believe that the City’s claim lacks merit. Accordingly, Generation has not recorded a liability for payment resulting from such a revocation, nor can Generation estimate a reasonably possible range of loss, if any, associated with any such revocation. Further, it is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2019, could be material to Generation’s results of operations and cash flows.
General (All Registrants)
The Registrants cannotare involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate whether they will incuran 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
See Note 12 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

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

18. 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 three and nine months ended September 30, 2018 and 2017.
 Three Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on decommissioning trust funds(a)
                 
Regulatory agreement units$214
 $214
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units58
 58
 —
 —
 —
 —
 —
 —
 —
Net unrealized (losses) gains on decommissioning trust funds                 
Regulatory agreement units(66) (66) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units72
 72
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                 
Zion Station decommissioning(9) (9) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(110) (110) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities159
 159
 —
 $—
 —

—
 —
 —
 —
Investment income9
 5
 —
 —
 —
 2
 1
 1
 —
Interest income related to uncertain income tax positions1
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity16
 —
 4
 1
 5
 6
 6
 —
 —
Non-service net periodic benefit cost(12) —
 —
 —
 —
 —
 —
 —
 —
Other21
 15
 3
 1
 —
 3
 —
 1
 1
Other, net$194

$179

$7

2

$5

$11

$7

$2

$1

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

 Nine Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on decommissioning trust funds(a)
                 
Regulatory agreement units$476
 $476
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units257
 257
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on decommissioning trust funds                 
Regulatory agreement units(335) (335) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units(143) (143) —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                 
Zion Station decommissioning(7) (7) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(110) (110) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities138
 138
 —
 —
 —
 —

—
 —
 —
Investment income19
 12
 —
 —
 —
 3
 1
 1
 —
Interest income related to uncertain income tax positions5
 1
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity47
 —
 12
 3
 13
 19
 17
 2
 —
Non-service net periodic benefit cost(33) —
 —
 —
 —
 —
 —
 —
 —
Other36
 13
 9
 1
 1
 11
 5
 4
 2
Other, net$212

$164

$21

$4

$14
 $33

$23

$7

$2
 Three Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on decommissioning trust funds(a)
                 
Regulatory agreement units$159
 $159
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units59
 59
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on decommissioning trust funds                 
Regulatory agreement units44
 44
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units111
 111
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                 
Zion Station decommissioning(4) (4) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(161) (161) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities208
 208
 —
 —
 —

—

—
 —
 —
Investment income2
 1
 —
 —
 —
 1
 1
 —
 —
Interest expense related to uncertain income tax positions4
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity17
 —
 2
 2
 4
 9
 6
 2
 1
Non-service net periodic benefit cost(27) —
 —
 —
 —
 —
 —
 —
 —
Other6
 —
 3
 —
 —
 3
 —
 2
 —
Other, net$210

$209

$5

$2

$4
 $13

$7

$4

$1

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

 Nine Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on decommissioning trust funds(a)
                 
Regulatory agreement units$439
 $439
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units165
 165
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on decommissioning trust funds                 
Regulatory agreement units253
 253
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units347
 347
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                 
Zion Station decommissioning(5) (5) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(558) (558) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities641
 641
 —
 —
 —
 —

—
 —
 —
Investment income6
 4
 —
 —
 —
 2
 1
 —
 —
Interest income related to uncertain income tax positions3
 —
 —
 —
 —
 —
 —
 —
 —
Penalty income related to uncertain income tax positions2
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity51
 —
 6
 6
 12
 27
 17
 5
 5
Non-service net periodic benefit cost(82) —
 —
 —
 —
 —
 —
 —
 —
Other22
 3
 8
 —
 —
 11
 4
 5
 1
Other, net$643

$648

$14

$6

$12
 $40

$22
 $10
 $6
_________
(a)Includes investment income and realized gains and losses on sales of investments of the trust funds.
(b)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 15 — Asset Retirement Obligations of the Exelon 2017 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
The following utility taxes are included in revenues and expenses for the three and nine months ended September 30, 2018 and 2017. Generation’s utility tax expense represents gross receipts tax related to its retail operations, and the Utility Registrants' utility tax expense represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
 Three Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$253

$32

$67

$39

$23
 $92
 $87

$5

$—
 Nine Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$705

$92

$188

$102

$70
 $253
 $238

$15

$—
 Three Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$245

$35

$65

$35

$22
 $88
 $83

$5

$—

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

 Nine Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$682

$97

$181

$95

$69
 $240
 $226

$14

$—
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the nine months ended September 30, 2018 and 2017.
 Nine Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization and accretion                 
Property, plant and equipment(a)
$2,829
 $1,347
 $613
 $204
 $249
 $355
 $161
 $97
 $70
Amortization of regulatory assets(a)
412
 —
 83
 20
 109
 200
 125
 38
 37
Amortization of intangible assets, net(a)
43
 36
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
8
 8
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
852
 852
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
367
 365
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$4,511

$2,608

$696

$224

$358
 $555
 $286

$135

$107
 Nine Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization and accretion                 
Property, plant and equipment(a)
$2,416
 $1,010
 $579
 $194
 $233
 $342
 $153
 $92
 $66
Amortization of regulatory assets(a)
355
 —
 52
 19
 115
 169
 89
 32
 47
Amortization of intangible assets, net(a)
43
 36
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
19
 19
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
816
 816
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
350
 350
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$3,999

$2,231

$631

$213

$348
 $511
 $242

$124

$113
_________
(a)Included in Depreciation and amortization on the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(b)Included in Operating revenues or Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(d)Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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

 Nine Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:                 
Pension and non-pension postretirement benefit costs$435
 $151
 $133
 $14
 $43
 $51
 $10
 $5
 $10
Loss (gain) from equity method investments22
 23
 —
 —
 —
 (1) —
 —
 —
Provision for uncollectible accounts133
 38
 30
 25
 6
 32
 12
 6
 14
Stock-based compensation costs64
 —
 —
 —
 —
 —
 —
 —
 —
Other decommissioning-related activity(a)
(39) (39) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
4
 4
 —
 —
 —
 —
 —
 —
 —
Amortization of regulatory asset related to debt costs6
 —
 2
 —
 —
 3
 1
 1
 1
Amortization of rate stabilization deferral—
 —
 —
 —
 —
 —
 —
 —
 —
Amortization of debt fair value adjustment(12) (9) —
 —
 —
 (3) —
 —
 —
Discrete impacts from EIMA and FEJA(c)
27
 —
 27
 —
 —
 —
 —
 —
 —
Amortization of debt costs26
 10
 4
 1
 1
 3
 2
 1
 —
Provision for excess and obsolete inventory15
 13
 2
 —
 —
 —
 —
 —
 —
Long-term incentive plan84
 —
 —
 —
 —
 —
 —
 —
 —
Asset retirement costs20
 —
 —
 —
 —
 20
 22
 (1) (1)
Other19
 (4) (11) 1
 (8) 4
 (5) 4
 —
Total other non-cash operating activities$804

$187

$187

$41

$42
 $109
 $42

$16

$24
Non-cash investing and financing activities:              
(Decrease) increase in capital expenditures not paid$(175) $(226) $(28) $4
 $44
 $54
 $15
 $20
 $16
Increase in PPE related to ARO update67
 47
 4
 —
 1
 15
 12
 2
 1
Dividends on stock compensation4
 —
 —
 —
 —
 —
 —

—
 —
Acquisition of land3
 —
 —
 —
 —
 3
 —
 —
 3

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

 Nine Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:                 
Pension and non-pension postretirement benefit costs$482
 $170
 $131
 $21
 $47
 $72
 $19
 $10
 $10
Loss from equity method investments26
 26
 —
 —
 —
 —
 —
 —
 —
Provision for uncollectible accounts103
 31
 25
 17
 4
 26
 11
 1
 14
Stock-based compensation costs76
 —
 —
 —
 —
 —
 —
 —
 —
Other decommissioning-related activity(a)
(213) (213) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
15
 15
 —
 —
 —
 —
 —
 —
 —
Amortization of regulatory asset related to debt costs7
 —
 3
 1
 —
 3
 1
 1
 1
Amortization of rate stabilization deferral(7) —
 —
 —
 7
 (14) (12) (2) —
Amortization of debt fair value adjustment(13) (9) —
 —
 —
 (4) —
 —
 —
Discrete impacts from EIMA and FEJA (c)
(61) —
 (61) —
 —
 —
 —
 —
 —
Amortization of debt costs57
 33
 3
 1
 1
 1
 1
 —
 —
Provision for excess and obsolete inventory52
 50
 1
 —
 —
 1
 —
 1
 —
Merger-related commitments(d)
—
 —
 —
 —
 —
 (8) (6) (2) —
Severance costs33
 25
 —
 —
 —
 3
 —
 —
 —
Other46
 4
 10
 (2) (7) (14) (6) (3) (4)
Total other non-cash operating activities$603

$132

$112

$38

$52
 $66
 $8

$6

$21
Non-cash investing and financing activities:                 
(Decrease) increase in capital expenditures not paid$(101) $20
 $(79) $(29) $16
 $(6) $7
 $14
 $(18)
Fair value of pension obligation transferred in connection with the FitzPatrick acquisition—
 33
 —
 —
 —
 —
 —
 —
 —
Decrease in PPE related to ARO update(141) (141) —
 —
 —
 —
 —
 —
 —
Indemnification of like-kind exchange tax position(e)
—
 —
 21
 —
 —
 —
 —
 —
 —
Non-cash financing of capital projects16
 16
 —
 —
 —
 —
 —
 —
 —
Dividends on stock compensation5
 —
 —
 —
 —
 —
 —
 —
 —
Dissolution of financing trust due to long-term debt retirement8
 —
 —
 —
 8
 —
 —
 —
 —
Fair value adjustment of long-term debt due to retirement(5) —
 —
 —
 —
 —
 —
 —
 —
_________
(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations of the Exelon 2017 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded in Operating revenues and expenses.
(c)Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 6 — Regulatory Matters for additional information.
(d)
See Note 4 - Mergers, Acquisitions and Dispositions for additional information.
(e)See Note 12 - Income Taxes for additional information on the like-kind exchange tax position.

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

The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
September 30, 2018Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$1,918
 $1,187
 $124
 $102
 $113
 $153
 $12
 $110
 $11
Restricted cash240
 152
 12
 5
 3
 42
 35
 —
 7
Restricted cash included in other long-term assets163
 —
 144
 —
 —
 19
 —
 —
 19
Total cash, cash equivalents and restricted cash$2,321
 $1,339
 $280
 $107
 $116
 $214
 $47
 $110
 $37
December 31, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$898
 $416
 $76
 $271
 $17
 $30
 $5
 $2
 $2
Restricted cash207
 138
 5
 4
 1
 42
 35
 —
 6
Restricted cash included in other long-term assets85
 —
 63
 —
 —
 23
 —
 —
 23
Total cash, cash equivalents and restricted cash$1,190
 $554
 $144
 $275
 $18
 $95
 $40
 $2
 $31
September 30, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$1,203
 $360
 $257
 $330
 $29
 $137
 $117
 $3
 $5
Restricted cash320
 186
 52
 4
 1
 43
 34
 —
 9
Restricted cash included in other long-term assets22
 —
 —
 —
 —
 22
 —
 —
 22
Total cash, cash equivalents and restricted cash$1,545
 $546
 $309
 $334
 $30
 $202
 $151
 $3
 $36
December 31, 2016Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$635
 $290
 $56
 $63
 $23
 $170
 $9
 $46
 $101
Restricted cash253
 158
 2
 4
 24
 43
 33
 —
 9
Restricted cash included in other long-term assets26
 —
 —
 —
 3
 23
 —
 —
 23
Total cash, cash equivalents and restricted cash$914
 $448
 $58
 $67
 $50
 $236
 $42
 $46
 $133
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K. 
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2018 and December 31, 2017.
September 30, 2018Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:                 
Accumulated depreciation and amortization$23,122
(a) 
$12,753
(a)  
$4,557

$3,521

$3,579
 $759
 $3,311

$1,315

$1,121
Accounts receivable:                 
Allowance for uncollectible accounts$354

$112

$93

$61

$22
 $66
 $25

$16

$25

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

December 31, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:                 
Accumulated depreciation and amortization$21,064
(b) 
$11,428
(b) 
$4,269

$3,411

$3,405
 $487
 $3,177

$1,247

$1,066
Accounts receivable:                 
Allowance for uncollectible accounts$322

$114

$73

$56

$24
 $55
 $21

$16

$18
_________
(a)Includes accumulated amortization of nuclear fuel in the reactor core of $3,278 million.
(b)Includes accumulated amortization of nuclear fuel in the reactor core of $3,159 million.
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 one year. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other significant liabilitiesdeferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $11 million as of September 30, 2018 and December 31, 2017. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2018 and December 31, 2017 of $11 million consists of $3 million and $8 million for medium risk and high risk segments, respectively. See Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K for additional investigationinformation regarding uncollectible accounts reserve methodology and remediationassessment of the credit quality of the installment plan receivables.
19. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants.
Exelon has twelve reportable segments, which include 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.
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.

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

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 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.

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 three and nine months ended September 30, 2018 and 2017 is as follows:
Three Months Ended September 30, 2018 and 2017
 
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Operating revenues(c):
               
2018
Competitive businesses electric revenues$4,741
 $—
 —
 $—
 $—
 $—
 $(306) $4,435
Competitive businesses natural gas revenues397
 —
 —
 —
 —
 —
 —
 397
Competitive businesses other revenues140
 —
 —
 —
 —
 —
 (1) 139
Rate-regulated electric revenues—
 1,598
 700
 645
 1,334
 —
 (7) 4,270
Rate-regulated natural gas revenues—
 —
 57
 86
 24
 —
 (5) 162
Shared service and other revenues—
 —
 —
 —
 3
 458
 (461) —
Total operating revenues$5,278
 $1,598
 $757
 $731
 $1,361
 $458
 $(780) $9,403
2017               
Competitive businesses electric revenues$4,041
 $—
 $—
 $—
 $—
 $—
 $(295) $3,746
Competitive businesses natural gas revenues460
 —
 —
 —
 —
 —
 —
 460
Competitive businesses other revenues249
 —
 —
 —
 —
 —
 —
 249
Rate-regulated electric revenues—
 1,571
 662
 658
 1,280
 —
 (7) 4,164
Rate-regulated natural gas revenues—
 —
 53
 80
 18
 —
 (2) 149
Shared service and other revenues—
 —
 —
 —
 12
 446
 (458) —
Total operating revenues$4,750
 $1,571
 $715
 $738
 $1,310
 $446
 $(762) $8,768
Intersegment revenues(d):
               
2018$308
 $4
 $2
 $6
 $3
 $456
 $(779) $—
2017294
 3
 2
 3
 12
 445
 (759) —
Net income (loss):              
2018$300
 $193
 $126
 $63
 $187
 $(69) $—
 $800
2017346
 189
 112
 62
 153
 3
 —
 865
Total assets:              
September 30, 2018$48,207
 $31,119
 $10,621
 $9,541
 $21,957
 $8,418
 $(10,378) $119,485
December 31, 201748,457
 29,726
 10,170
 9,104
 21,247
 8,618
 (10,552) 116,770
                

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

__________
(a)Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the three months ended September 30, 2018 include revenue from sales to PECO of $35 million, sales to BGE of $69 million, sales to Pepco of $46 million, sales to DPL of $26 million and sales to ACE of $10 million in the Mid-Atlantic region, and sales to ComEd of $122 million in the Midwest region, which eliminate upon consolidation. For the three months ended September 30, 2017, intersegment revenues for Generation include revenue from sales to PECO of $31 million, sales to BGE of $98 million, sales to Pepco of $57 million, sales to DPL of $47 million and sales to ACE of $7 million in the Mid-Atlantic region, and sales to ComEd of $54 million in the Midwest region, which eliminate upon consolidation.
(b)Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(c)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 18 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 2018 and 2017.
(d)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.
PHI:
 Pepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHI
Operating revenues(a):
Three Months Ended September 30, 2018           
Rate-regulated electric revenues$628
 $304
 $406
 $—
 $(4) $1,334
Rate-regulated natural gas revenues—
 24
 —
 —
 —
 24
Shared service and other revenues—
 —
 —
 103
 (100) 3
Total operating revenues$628
 $328
 $406
 $103
 $(104) $1,361
Three Months Ended September 30, 2017           
Rate-regulated electric revenues$604
 $309
 $370
 $—
 $(3) $1,280
Rate-regulated natural gas revenues—
 18
 —
 —
 —
 18
Shared service and other revenues—
 —
 —
 12
 —
 12
Total operating revenues$604
 $327
 $370
 $12
 $(3) $1,310
Intersegment revenues:           
Three Months Ended September 30, 2018$2
 $2
 $1
 $103
 $(105) $3
Three Months Ended September 30, 20171
 2
 —
 13
 (4) 12
Net income (loss):           
Three Months Ended September 30, 2018$89
 $33
 $61
 $1
 $3
 $187
Three Months Ended September 30, 201787
 31
 41
 (18) 12
 153
Total assets:           
September 30, 2018$8,199
 $4,601
 $3,694
 $10,763
 $(5,300) $21,957
December 31, 20177,832
 4,357
 3,445
 10,600
 (4,987) 21,247
__________
(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 18 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 2018 and 2017.
(b)Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors for three months ended September 30, 2018 and 2017. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.

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

Competitive Business Revenues (Generation):
 Three Months Ended September 30, 2018
 
Revenues from external parties(a)
 Intersegment
revenues
Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$1,397
 $52
 $1,449
 $7
 $1,456
Midwest1,095
 26
 1,121
 (4) 1,117
New England666
 33
 699
 —
 699
New York475
 (6) 469
 —
 469
ERCOT156
 289
 445
 (1) 444
Other Power Regions293
 265
 558
 (45) 513
Total Competitive Businesses Electric Revenues4,082
 659
 4,741
 (43) 4,698
Competitive Businesses Natural Gas Revenues200
 197
 397
 43
 440
Competitive Businesses Other Revenues(c)
130
 10
 140
 —
 140
Total Generation Consolidated Operating Revenues$4,412
 $866
 $5,278
 $—
 $5,278
 Three Months Ended September 30, 2017
 
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$1,397
 $24
 $1,421
 $11
 $1,432
Midwest982
 67
 1,049
 (11) 1,038
New England504
 (22) 482
 (1) 481
New York454
 (21) 433
 (6) 427
ERCOT164
 144
 308
 6
 314
Other Power Regions167
 181
 348
 (13) 335
Total Competitive Businesses Electric Revenues3,668
 373
 4,041
 (14) 4,027
Competitive Businesses Natural Gas Revenues226
 234
 460
 20
 480
Competitive Businesses Other Revenues(c)
207
 42
 249
 (6) 243
Total Generation Consolidated Operating Revenues$4,101
 $649
 $4,750
 $—
 $4,750
__________
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $13 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the three months ended September 30, 2017, unrealized mark-to-market gains of $6 million and $52 million for the three months ended September 30, 2018 and 2017, respectively, and elimination of intersegment revenues.

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

Revenues net of purchased power and fuel expense (Generation):
 Three Months Ended September 30, 2018 Three Months Ended September 30, 2017
 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
Mid-Atlantic$746
 $17
 $763
 $817
 $38
 $855
Midwest763
 5
 768
 697
 —
 697
New England83
 (2) 81
 151
 (6) 145
New York290
 2
 292
 295
 —
 295
ERCOT161
 (63) 98
 229
 (111) 118
Other Power Regions143
 (44) 99
 118
 (50) 68
Total Revenues net of purchased power and fuel for Reportable Segments2,186

(85)
2,101

2,307

(129)
2,178
Other(b)
112
 85
 197
 112
 129
 241
Total Generation Revenues net of purchased power and fuel expense$2,298

$—

$2,298

$2,419

$—

$2,419
__________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $19 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the three months ended September 30, 2017, unrealized mark-to-market gains of $71 million and $73 million for the three months ended September 30, 2018 and 2017, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 - Early Plant Retirements of $18 million and $6 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2018, and 2017, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

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

Electric and Gas Revenue by Customer Class (the Utility Registrants):
 Three Months Ended September 30, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$861
 $458
 $366
 $726
 $306
 $180
 $240
Small commercial & industrial391
 108
 68
 140
 39
 48
 53
Large commercial & industrial131
 64
 117
 303
 230
 25
 48
Public authorities & electric railroads11
 7
 7
 14
 8
 3
 3
Other(a)
212
 59
 91
 156
 47
 47
 63
Total rate-regulated electric revenues(b)
1,606
 696
 649
 1,339
 630
 303
 407
Rate-regulated natural gas revenues             
Residential—
 36
 46
 8
 —
 8
 —
Small commercial & industrial—
 15
 8
 5
 —
 5
 —
Large commercial & industrial—
 —
 17
 2
 —
 2
 —
Transportation—
 5
 —
 3
 —
 3
 —
Other(c)
—
 1
 12
 6
 —
 6
 —
Total rate-regulated natural gas revenues(d)
—
 57
 83
 24
 —
 24
 —
Total rate-regulated revenues from contracts with customers1,606
 753
 732
 1,363
 630
 327
 407
              
Other revenues             
Revenues from alternative revenue programs(15) 1
 (6) (5) (4) —
 (1)
Other rate-regulated electric revenues(e)
7
 3
 4
 3
 2
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 1
 —
 —
 —
 —
Total other revenues(8) 4
 (1) (2) (2) 1
 (1)
Total rate-regulated revenues for reportable segments$1,598
 $757
 $731
 $1,361
 $628
 $328
 $406

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

 Three Months Ended September 30, 2017
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$816
 $434
 $352
 $687
 $291
 $185
 $211
Small commercial & industrial366
 106
 65
 140
 37
 50
 53
Large commercial & industrial119
 59
 114
 288
 211
 28
 49
Public authorities & electric railroads11
 7
 8
 14
 8
 3
 3
Other(a)
235
 53
 85
 147
 52
 43
 54
Total rate-regulated electric revenues(b)
1,547
 659
 624
 1,276
 599
 309
 370
Rate-regulated natural gas revenues             
Residential—
 33
 44
 8
 —
 8
 —
Small commercial & industrial—
 14
 8
 3
 —
 3
 —
Large commercial & industrial—
 —
 19
 1
 —
 1
 —
Transportation—
 5
 —
 3
 —
 3
 —
Other(c)
—
 1
 3
 3
 —
 3
 —
Total rate-regulated natural gas revenues(d)
—
 53
 74
 18
 —
 18
 —
Total rate-regulated revenues from contracts with customers1,547
 712
 698
 1,294
 599
 327
 370
              
Other revenues             
Revenues from alternative revenue programs16
 —
 36
 2
 3
 (1) —
Other rate-regulated electric revenues(e)
8
 3
 3
 3
 2
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 1
 —
 —
 —
 —
Other revenues(f)
—
 —
 —
 11
 —
 —
 —
Total other revenues24
 3
 40
 16
 5
 —
 —
Total rate-regulated revenues for reportable segments$1,571
 $715
 $738
 $1,310
 $604
 $327
 $370
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $4 million, $2 million, $1 million, $3 million, $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the three months ended September 30, 2018 and $3 million, $1 million, $1 million, $1 million $1 million, $2 million and less than $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the three months ended September 30, 2017.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of less than $1 million and $5 million at PECO and BGE, respectively, for the three months ended September 30, 2018 and less than $1 million and $2 million at PECO and BGE, respectively, for the three months ended September 30, 2017.
(e)Includes late payment charge revenues.
(f)Includes operating revenues from affiliates of $11 million at PHI for the three months ended September 30, 2017.

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

Nine Months Ended September 30, 2018 and 2017
 
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Operating revenues(c):
2018               
Competitive businesses electric revenues$13,190
 $—
 $—
 $—
 $—
 $—
 $(969) $12,221
Competitive businesses natural gas revenues1,839
 —
 —
 —
 —
 —
 (8) 1,831
Competitive businesses other revenues339
 —
 —
 —
 —
 —
 (4) 335
Rate-regulated electric revenues—
 4,508
 1,893
 1,850
 3,549
 —
 (34) 11,766
Rate-regulated natural gas revenues—
 —
 382
 519
 129
 —
 (13) 1,017
Shared service and other revenues—
 —
 —
 —
 10
 1,398
 (1,408) —
Total operating revenues$15,368
 $4,508
 $2,275
 $2,369
 $3,688
 $1,398
 $(2,436) $27,170
2017               
Competitive businesses electric revenues$11,514
 $—
 $—
 $—
 $—
 $—
 $(888) $10,626
Competitive businesses natural gas revenues1,807
 —
 —
 —
 —
 —
 —
 1,807
Competitive businesses other revenues522
 —
 —
 —
 —
 —
 —
 522
Rate-regulated electric revenues—
 4,227
 1,802
 1,895
 3,417
 —
 (23) 11,318
Rate-regulated natural gas revenues—
 —
 339
 468
 105
 —
 (6) 906
Shared service and other revenues—
 —
 —
 —
 35
 1,316
 (1,350) 1
Total operating revenues$13,843
 $4,227
 $2,141
 $2,363
 $3,557
 $1,316
 $(2,267) $25,180
Intersegment revenues(d):
               
2018$981
 $23
 $5
 $18
 $11
 $1,392
 $(2,430) $—
2017888
 12
 5
 12
 35
 1,312
 (2,262) 2
Net income (loss):               
2018$667
 $523
 $336
 $242
 $336
 $(125) $—
 $1,979
2017508
 447
 327
 231
 359
 58
 (2) 1,928
__________
(a)Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the nine months ended September 30, 2018 include revenue from sales to PECO of $97 million, sales to BGE of $198 million, sales to Pepco of $143 million, sales to DPL of $103 million and sales to ACE of $21 million in the Mid-Atlantic region, and sales to ComEd of $419 million in the Midwest region, which eliminate upon consolidation. For the nine months ended September 30, 2017, intersegment revenues for Generation include revenue from sales to PECO of $111 million, sales to BGE of $330 million, sales to Pepco of $209 million, sales to DPL of $138 million and sales to ACE of $23 million in the Mid-Atlantic region, and sales to ComEd of $77 million in the Midwest region, which eliminate upon consolidation.
(b)Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(c)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 18 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 2018 and 2017.

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

(d)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.
PHI:
 Pepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHI
Operating revenues(a):
           
Nine Months Ended September 30, 2018           
Rate-regulated electric revenues$1,708
 $872
 $981
 $—
 $(12) $3,549
Rate-regulated natural gas revenues—
 129
 —
 —
 —
 129
Shared service and other revenues—
 —
 —
 326
 (316) 10
Total operating revenues$1,708
 $1,001
 $981
 $326
 $(328) $3,688
Nine Months Ended September 30, 2017           
Rate-regulated electric revenues$1,649
 $866
 $915
 $—
 $(13) $3,417
Rate-regulated natural gas revenues—
 105
 —
 —
 —
 105
Shared service and other revenues—
 —
 —
 37
 (2) 35
Total operating revenues$1,649
 $971
 $915
 $37
 $(15) $3,557
Intersegment revenues:           
Nine Months Ended September 30, 2018$5
 $6
 $2
 $325
 $(327) $11
Nine Months Ended September 30, 20174
 6
 2
 37
 (14) 35
Net income (loss):           
Nine Months Ended September 30, 2018$174
 $90
 $76
 $(15) $11
 $336
Nine Months Ended September 30, 2017188
 107
 77
 (48) 35
 359
__________
(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 18 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 2018 and 2017.
(b)Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors for nine months ended September 30, 2018 and 2017. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants but exclude any intercompany revenues.

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

Competitive Business Revenues (Generation):
 Nine Months Ended September 30, 2018
 
Revenues from external parties(a)
 
Intersegment
Revenues
 
Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$3,971
 $191
 $4,162
 $17
 $4,179
Midwest3,432
 169
 3,601
 (8) 3,593
New England1,943
 87
 2,030
 (4) 2,026
New York1,305
 (37) 1,268
 1
 1,269
ERCOT470
 459
 929
 1
 930
Other Power Regions713
 487
 1,200
 (112) 1,088
Total Competitive Businesses Electric Revenues11,834
 1,356
 13,190
 (105) 13,085
Competitive Businesses Natural Gas Revenues1,016
 823
 1,839
 105
 1,944
Competitive Businesses Other Revenues(c)
385
 (46) 339
 —
 339
Total Generation Consolidated Operating Revenues$13,235
 $2,133
 $15,368
 $—
 $15,368
 Nine Months Ended September 30, 2017
 
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$4,260
 $(53) $4,207
 $15
 $4,222
Midwest2,948
 210
 3,158
 (17) 3,141
New England1,555
 (86) 1,469
 (8) 1,461
New York1,161
 (37) 1,124
 (14) 1,110
ERCOT520
 229
 749
 4
 753
Other Power Regions439
 368
 807
 (28) 779
Total Competitive Businesses Electric Revenues10,883
 631
 11,514
 (48) 11,466
Competitive Businesses Natural Gas Revenues1,237
 570
 1,807
 52
 1,859
Competitive Businesses Other Revenues(c)
588
 (66) 522
 (4) 518
Total Generation Consolidated Operating Revenues$12,708
 $1,135
 $13,843
 $—
 $13,843
__________
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $30 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the nine months ended September 30, 2017, unrealized mark-to-market losses of $96 million and $47 million for the nine months ended September 30, 2018 and 2017, respectively, and elimination of intersegment revenues.

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

Revenues net of purchased power and fuel expense (Generation):
 Nine Months Ended September 30, 2018 Nine Months Ended September 30, 2017
 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
Mid-Atlantic$2,303
 $45
 $2,348
 $2,330
 $81
 $2,411
Midwest2,381
 19
 2,400
 2,129
 11
 2,140
New England310
 (12) 298
 423
 (20) 403
New York832
 9
 841
 708
 (1) 707
ERCOT396
 (180) 216
 446
 (188) 258
Other Power Regions430
 (121) 309
 359
 (139) 220
Total Revenues net of purchased power and fuel expense for Reportable Segments6,652

(240)
6,412

6,395

(256)
6,139
Other(b)
164
 240
 404
 162
 256
 418
Total Generation Revenues net of purchased power and fuel expense$6,816

$—

$6,816

$6,557

$—

$6,557
__________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $41 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the nine months ended September 30, 2017, unrealized mark-to-market losses of $104 million and $161 million for the nine months ended September 30, 2018 and 2017, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 - Early Plant Retirements of $53 million and $8 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2018 and 2017, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

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

Electric and Gas Revenue by Customer Class (the Utility Registrants):
 Nine Months Ended September 30, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$2,277
 $1,199
 $1,054
 $1,839
 $792
 $513
 $534
Small commercial & industrial1,132
 306
 196
 370
 104
 138
 128
Large commercial & industrial411
 174
 325
 845
 632
 74
 139
Public authorities & electric railroads36
 21
 21
 44
 24
 10
 10
Other(a)
656
 181
 246
 446
 145
 129
 174
Total rate-regulated electric revenues(b)
4,512
 1,881
 1,842
 3,544
 1,697
 864
 985
Rate-regulated natural gas revenues             
Residential—
 259
 345
 68
 —
 68
 —
Small commercial & industrial—
 102
 55
 31
 —
 31
 —
Large commercial & industrial—
 1
 88
 7
 —
 7
 —
Transportation—
 16
 —
 12
 —
 12
 —
Other(c)
—
 4
 49
 11
 —
 11
 —
Total rate-regulated natural gas revenues(d)
—
 382
 537
 129
 —
 129
 —
Total rate-regulated revenues from contracts with customers4,512
 2,263
 2,379
 3,673
 1,697
 993
 985
              
Other revenues             
Revenues from alternative revenue programs(27) 2
 (23) 7
 6
 5
 (4)
Other rate-regulated electric revenues(e)
23
 10
 10
 8
 5
 3
 —
Other rate-regulated natural gas revenues(e)
—
 —
 3
 —
 —
 —
 —
Total other revenues(4) 12
 (10) 15
 11
 8
 (4)
Total rate-regulated revenues for reportable segments$4,508
 $2,275
 $2,369
 $3,688
 $1,708
 $1,001
 $981

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

 Nine Months Ended September 30, 2017
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$2,071
 $1,147
 $1,038
 $1,740
 $751
 $505
 $484
Small commercial & industrial1,035
 303
 193
 373
 105
 139
 129
Large commercial & industrial346
 168
 329
 814
 593
 78
 143
Public authorities & electric railroads33
 23
 23
 45
 24
 11
 10
Other(a)
671
 151
 222
 398
 148
 121
 140
Total rate-regulated electric revenues(b)
4,156
 1,792
 1,805
 3,370
 1,621
 854
 906
Rate-regulated natural gas revenues             
Residential—
 225
 289
 57
 —
 57
 —
Small commercial & industrial—
 90
 51
 25
 —
 25
 —
Large commercial & industrial—
 —
 82
 5
 —
 5
 —
Transportation—
 16
 —
 11
 —
 11
 —
Other(c)
—
 8
 20
 7
 —
 7
 —
Total rate-regulated natural gas revenues(d)
—
 339
 442
 105
 —
 105
 —
Total rate-regulated revenues from contracts with customers4,156
 2,131
 2,247
 3,475
 1,621
 959
 906
              
Other revenues             
Revenues from alternative revenue programs48
 —
 102
 41
 23
 9
 9
Other rate-regulated electric revenues(e)
23
 10
 11
 8
 5
 3
 —
Other rate-regulated natural gas revenues(e)
—
 —
 3
 —
 —
 —
 —
Other revenues(f)
—
 —
 —
 33
 —
 —
 —
Total other revenues71
 10
 116
 82
 28
 12
 9
Total rate-regulated revenues for reportable segments$4,227
 $2,141
 $2,363
 $3,557
 $1,649
 $971
 $915
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $23 million, $5 million, $5 million, $11 million, $5 million, $6 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the nine months ended September 30, 2018 and $12 million, $4 million, $5 million, $2 million, $4 million, $6 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the nine months ended September 30, 2017.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of less than $1 million and $13 million at PECO and BGE, respectively, for the nine months ended September 30, 2018 and less than $1 million and $7 million at PECO and BGE, respectively, for the nine months ended September 30, 2017.
(e)Includes late payment charge revenues.
(f)Includes operating revenues from affiliates of $33 million at PHI for the nine months ended September 30, 2017.

Table of Contents

Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations
(Dollars in millions except per share data, unless otherwise noted)
Exelon
Executive Overview
Exelon, 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 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 19 — 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 corporate governance support services including corporate strategy and development, legal, human resources, information technology, finance, real estate, security, corporate communications and

Table of Contents

supply at cost. The costs of these services are directly charged or allocated to the applicable operating segments. The services are provided pursuant to service agreements. Additionally, the results of Exelon’s corporate operations include interest costs income from various investment and financing activities.
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 PHISCO and the participating operating subsidiaries.
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.

Table of Contents

Financial Results of Operations
GAAP Results of Operations
The following tables set forth Exelon's GAAP consolidated results of operations for the three and nine months ended September 30, 2018 compared to the same period in 2017. All amounts presented below are before the impact of income taxes, except as noted.
 Three Months Ended September 30, Favorable
(Unfavorable)
Variance
 2018 2017 
 Generation ComEd PECO BGE PHI Other Exelon Exelon 
Operating revenues$5,278
 $1,598
 $757
 $731
 $1,361
 $(322) $9,403
 $8,768
 $635
Purchased power and fuel expense2,980
 619
 263
 272
 509
 (311) 4,332
 3,542
 (790)
Revenue net of purchased power and fuel expense(a)
2,298
 979
 494
 459
 852
 (11) 5,071
 5,226
 (155)
Other operating expenses                 
Operating and maintenance1,370
 337
 219
 182
 292
 (54) 2,346
 2,275
 (71)
Depreciation and amortization468
 237
 75
 110
 192
 23
 1,105
 1,002
 (103)
Taxes other than income143
 82
 46
 64
 123
 11
 469
 456
 (13)
Total other operating expenses1,981
 656
 340
 356
 607
 (20) 3,920
 3,733
 (187)
(Loss) gain on sales of assets and businesses(6) —
 —
 —
 —
 1
 (5) (1) (4)
Bargain purchase gain—
 —
 —
 —
 —
 —
 —
 7
 (7)
Operating income311
 323
 154
 103
 245
 10
 1,146
 1,499
 (353)
Other income and (deductions)                 
Interest expense, net(101) (85) (32) (27) (65) (83) (393) (386) (7)
Other, net179
 7
 2
 5
 11
 (10) 194
 210
 (16)
Total other income and (deductions)78
 (78) (30) (22) (54) (93) (199) (176) (23)
Income (loss) before income taxes389
 245
 124
 81
 191
 (83) 947
 1,323
 (376)
Income taxes78
 52
 (2) 18
 4
 (13) 137
 451
 314
Equity in (losses) earnings of unconsolidated affiliates(11) —
 —
 —
 —
 1
 (10) (7) (3)
Net income (loss)300
 193
 126
 63
 187
 (69) 800
 865
 (65)
Net income attributable to noncontrolling interests66
 —
 —
 —
 —
 1
 67
 42
 (25)
Net income (loss) attributable to common shareholders$234
 $193
 $126
 $63
 $187
 $(70) $733
 $823
 $(90)

Table of Contents

 Nine Months Ended September 30, 
Favorable
(Unfavorable)
Variance
 2018 2017 
 Generation ComEd PECO BGE PHI Other Exelon Exelon 
Operating revenues$15,368
 $4,508
 $2,275
 $2,369
 $3,688
 $(1,038) $27,170
 $25,180
 $1,990
Purchased power and fuel expense8,552
 1,702
 818
 881
 1,410
 (989) 12,374
 10,527
 (1,847)
Revenue net of purchased power and fuel expense(a)
6,816

2,806

1,457

1,488

2,278
 (49)
14,796

14,653
 143
Other operating expenses        

        
Operating and maintenance4,126
 974
 686
 578
 857
 (185) 7,036
 7,658
 622
Depreciation and amortization1,383
 696
 224
 358
 555
 68
 3,284
 2,814
 (470)
Taxes other than income414
 238
 125
 188
 343
 34
 1,342
 1,313
 (29)
Total other operating expenses5,923

1,908

1,035

1,124

1,755
 (83)
11,662

11,785
 123
Gain on sales of assets and businesses48
 5
 1
 1
 —
 —
 55
 4
 51
Bargain purchase gain—
 —
 —
 —
 —
 —
 —
 233
 (233)
Operating income941

903

423

365

523
 34

3,189

3,105
 84
Other income and (deductions)                 
Interest expense, net(305) (261) (96) (78) (193) (205) (1,138) (1,194) 56
Other, net164
 21
 4
 14
 33
 (24) 212
 643
 (431)
Total other income and (deductions)(141)
(240)
(92)
(64)
(160) (229)
(926)
(551) (375)
Income (loss) before income taxes800
 663
 331
 301
 363
 (195) 2,263
 2,554
 (291)
Income taxes110
 140
 (5) 59
 28
 (70) 262
 601
 339
Equity in (losses) earnings of unconsolidated affiliates(23) —
 —
 —
 1
 —
 (22) (25) 3
Net income (loss)667

523

336

242

336

(125)
1,979

1,928
 51
Net income attributable to noncontrolling interests120
 —
 —
 —
 —
 1
 121
 21
 (100)
Net income (loss) attributable to common shareholders$547

$523

$336

$242

$336
 $(126)
$1,858

$1,907
 $(49)
_________
(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 their 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.
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017.Exelon’s Net income attributable to common shareholders was $733 million for the three months ended September 30, 2018 as compared to $823 million for the three months ended September 30, 2017, and diluted earnings per average common share were $0.76 for the three months ended September 30, 2018 as compared to $0.85for the three months ended September 30, 2017.

Table of Contents

Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $155 million for the three months ended September 30, 2018 compared to the same period in 2017 primarily due to the following factors:
Decrease of $121 million at Generation primarily due to the absence of EGTP revenues net of purchased power and fuel expense resulting from its deconsolidation in the fourth quarter of 2017, lower realized energy prices, lower energy efficiency revenues and decreased revenues related to the sale of Generation's electrical contracting business in 2018 and increased nuclear outage days, partially offset by the impact of Illinois ZES and increased capacity prices;
Decrease of $113 million across all Utility Registrants, primarily reflecting lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates, partially offset by regulatory rate increases at ComEd, Pepco, DPL and ACE; and
Increase of $58 million at PECO, DPL and ACE primarily due to favorable weather conditions and volumes within their respective service territories.
Operating and maintenance expense increased by $71 million for the three months ended September 30, 2018 as compared to the same period in 2017 primarily due to the following factors:
Increase of $84 million at Generation due to a charge associated with a remeasurement of the Oyster Creek ARO;
Increase of $40 million at Generation due to higher nuclear refueling outage costs;
Increase of $22 million at Pepco due to a charge associated with a remeasurement of the Buzzard Point ARO; and
Decrease of $50 million at Generation in labor, contracting and materials expense due to decreased spending related to energy efficiency projects and decreased costs related to the sale of Generation's electrical contracting business in 2018.
Depreciation and amortization expense increased by $103 million for the three months ended September 30, 2018 as compared to the same period in 2017 primarily due to ongoing capital expenditures across all operating companies, accelerated depreciation and amortization due to Generation's decision to early retire the Oyster Creek and TMI nuclear facilities, increased amortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues), partially offset by certain regulatory assets that became fully amortized as of December 31, 2017 for BGE.
Other, net decreased by $16 million primarily due to lower net unrealized and realized gains on NDT funds at Generation for the three months ended September 30, 2018 compared to the same period in 2017.
Exelon’s effective income tax rates for the three months ended September 30, 2018 and 2017 were 14.5% and 34.1%, respectively. The decrease in the effective income tax rate for the three months ended September 30, 2018 compared to the same period in 2017 is primarily related to tax savings due to the lower federal income tax rate as a result of the TCJA at all Registrants, which is predominantly offset in Operating revenues at the Utility Registrants for the anticipated pass back of the tax savings through customer rates. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional sitesinformation regarding the components of the effective income tax rates. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on TCJA's impact on regulatory proceedings.

Table of Contents

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.Exelon’s Net income attributable to common shareholders was $1,858 million for the nine months ended September 30, 2018 compared to $1,907 million for the nine months ended September 30, 2017, and diluted earnings per average common share were $1.92 for the nine months ended September 30, 2018 compared to $2.02for the nine months ended September 30, 2017.
Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $143 million for the nine months ended September 30, 2018 as compared to the same period in 2017. The year-over-year increase in Revenue net of purchased power and fuel expense was primarily due to the following factors:
Increase of $202 million at Generation primarily due to impact of the New York CES and Illinois ZES (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017), increased capacity prices, the acquisition of the FitzPatrick nuclear facility and decreased nuclear outage days, the addition of two combined-cycle gas turbines in Texas and the impacts of Generation's natural gas portfolio, partially offset by lower realized energy prices, the absence of EGTP revenues net of purchased power and fuel expense resulting from its deconsolidation in the fourth quarter of 2017, lower energy efficiency revenues and decreased revenues related to the sale of Generation's electrical contracting business in 2018;
Increase of $57 million at Generation due to lower mark-to-market losses;
Increase of $132 million at PECO, DPL and ACE primarily due to favorable weather conditions and volumes within their respective service territories;
Increase of $33 million due to higher mutual assistance revenues across all Utility Registrants, primarily at ComEd;
Decrease of $95 million at ComEd primarily due to lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to FEJA; and
Decrease of $274 million in electric and gas revenues across all Utility Registrants, primarily reflecting lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates, partially offset by higher utility revenues due to regulatory rate increases at ComEd, BGE, Pepco, DPL and ACE.
Operating and maintenance expense decreased by $622 million for the nine months ended September 30, 2018 compared to the same period in 2017 primarily due to the following factors:
Decrease of $411 million at Generation due to long-lived asset impairments primarily related to the EGTP assets held for sale in 2017;
Decrease of $163 million at Generation in labor, contracting and materials expense due to decreased spending related to energy efficiency projects and decreased costs related to the sale of Generation's electrical contracting business in 2018.
Decrease of $95 million at ComEd primarily due to the change to defer and recover over time energy efficiency costs pursuant to FEJA;
Decrease of $66 million at Generation due to lower merger-related costs;
Decrease of $56 million at Generation due to lower nuclear refueling outage costs;
Decrease of $32 million due to a supplemental NEIL insurance distribution at Generation;

Table of Contents

Increase of $47 million due to higher one-time charges related to Generation's decision to early retire the Oyster Creek nuclear facility in 2018, including a remeasurement to the ARO, compared to one-time charges related to Generation’s decision to early retire the TMI nuclear facility in 2017;
Increase of $33 million due to higher mutual assistance expenses across all Utility Registrants, primarily at ComEd;
Increase of $97 million at PECO and BGE due to increased storm costs; and
Increase of $22 million at Pepco due to a charge associated with a remeasurement of the Buzzard Point ARO.
Depreciation and amortization expense increased by $470 million for the nine months ended September 30, 2018 compared to the same period in 2017 primarily due to increased depreciation expense as a result of ongoing capital expenditures across all operating companies, accelerated depreciation and amortization due to Generation's decision to early retire the Oyster Creek and TMI nuclear facilities, increased amortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues), partially offset by certain regulatory assets that became fully amortized as of December 31, 2017 for BGE.
Taxes other than income increased due to increased gross receipts tax accruals at PECO and Pepco for the nine months ended September 30, 2018 compared to the same period in 2017.
Gain on sales of assets and businesses increased by $51 million for the nine months ended September 30, 2018 compared to the same period in 2017 primarily due to Generation's sale of its electrical contracting business.
Bargain purchase gain decreased by $233 million due to the gain associated with the FitzPatrick acquisition in the first quarter of 2017.
Interest expense, net decreased by $56 million due to retirement of long-term debt.
Other, net decreased by $431 million primarily due to lower net unrealized and realized gains on NDT funds at Generation for the nine months ended September 30, 2018 compared to the same period in 2017.
Exelon’s effective income tax rates for the nine months ended September 30, 2018 and 2017 were 11.6% and 23.5%, respectively. The decrease in the effective income tax rate for the nine months ended September 30, 2018 compared to the same period in 2017 is primarily related to tax savings due to the lower federal income tax rate as a result of the TCJA at all Registrants, which is offset in Operating revenues at the Utility Registrants for the anticipated pass back of the tax savings through customer rates. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on TCJA's impact on regulatory proceedings.
For additional information regarding the financial results for the three and nine months ended September 30, 2018, including explanation of the non-GAAP measure Revenue net of purchased power and fuel expense, see the discussions of Results of Operations by Registrant below.
Adjusted (non-GAAP) Operating Earnings
Exelon’s adjusted (non-GAAP) operating earnings for the three months ended September 30, 2018 were $856 million, or $0.88 per diluted share, compared with adjusted (non-GAAP) operating earnings

Table of Contents

of $820 million, or $0.85 per diluted share for the same period in 2017. Exelon’s adjusted (non-GAAP) operating earnings for the nine months ended September 30, 2018 were $2,467 million, or $2.55 per diluted share, compared with adjusted (non-GAAP) operating earnings of $1,943 million, or $2.06 per diluted share for the same period in 2017. 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 period-over-period 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.

Table of Contents

The following tables provide a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2018 compared to the same period in 2017.
 Three Months Ended September 30,
 2018 2017
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$733
 $0.76
 $823
 $0.85
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $20 and $29, respectively)
(55) (0.06) (45) (0.05)
Unrealized Gains Related to NDT Fund Investments(b) (net of taxes of $4 and $51, respectively)
(53) (0.06) (67) (0.07)
Amortization of Commodity Contract Intangibles(c) (net of taxes of $0 and $8, respectively)
—
 —
 12
 0.01
Merger and Integration Costs(d) (net of taxes of $0 and $1, respectively)
—
 —
 (1) —
Long-Lived Asset Impairments(f) (net of taxes of $2 and $16, respectively)
6
 0.01
 24
 0.03
Plant Retirements and Divestitures(g) (net of taxes of $70 and $47, respectively)
202
 0.21
 71
 0.08
Cost Management Program(h) (net of taxes of $4 and $8, respectively)
13
 0.01
 13
 0.01
Bargain Purchase Gain(i) (net of taxes of $0 and $0, respectively)
—
 —
 (7) (0.01)
Asset Retirement Obligation(n) (net of taxes of $6 and $1, respectively)
16
 0.02
 (2) —
Change in Environmental Liabilities (net of taxes of $3 and $0, respectively)(9) (0.01) —
 —
Reassessment of Deferred Income Taxes(k) (entire amount represents tax expense)
(18) (0.02) (21) (0.02)
Noncontrolling Interests(m) (net of taxes of $4 and $4, respectively)
21
 0.02
 20
 0.02
Adjusted (non-GAAP) Operating Earnings$856
 $0.88
 $820
 $0.85

Table of Contents

 Nine Months Ended September 30,
 2018 2017
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$1,858
 $1.92
 $1,907
 $2.02
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $26 and $62, respectively)
74
 0.08
 97
 0.10
Unrealized Losses (Gains) Related to NDT Fund Investments(b) (net of taxes of $118 and $181, respectively)
94
 0.10
 (211) (0.22)
Amortization of Commodity Contract Intangibles(c) (net of taxes of $0 and $17, respectively)
—
 —
 27
 0.03
Merger and Integration Costs(d) (net of taxes of $1 and $24, respectively)
5
 —
 39
 0.04
Merger Commitments(e) (net of taxes of $0 and $137, respectively)
—
 —
 (137) (0.15)
Long-Lived Asset Impairments(f) (net of taxes of $13 and $188, respectively)
36
 0.04
 293
 0.31
Plant Retirements and Divestitures(g) (net of taxes of $148 and $89, respectively)
422
 0.43
 137
 0.15
Cost Management Program(h) (net of taxes of $10 and $15, respectively)
29
 0.03
 24
 0.03
Bargain Purchase Gain(i) (net of taxes of $0 and $0, respectively)
—
 —
 (233) (0.25)
Asset Retirement Obligation(n) (net of taxes of $6 and $1, respectively)
16
 0.02
 (2) —
Change in Environmental Liabilities (net of taxes of $1 and $0, respectively)(4) —
 —
 —
Like-Kind Exchange Tax Position(j) (net of taxes of $0 and $66, respectively)
—
 —
 (26) (0.03)
Reassessment of Deferred Income Taxes(k) (entire amount represents tax expense)
(27) (0.03) (42) (0.04)
Tax Settlements(l) (net of taxes of $0 and $1, respectively)
—
 —
 (5) (0.01)
Noncontrolling Interests(m) (net of taxes of $9 and $16, respectively)
(36) (0.04) 75
 0.08
Adjusted (non-GAAP) Operating Earnings$2,467
 $2.55
 $1,943
 $2.06
_________
Note:
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2018 and 2017 ranged from 26.0 percent to 29.0 percent and 39.0 percent to 41.0 percent, respectively. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 7.7 percent and 43.2 percent for the three months ended September 30, 2018 and 2017, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 55.5 percent and 46.2 percent for the nine months ended September 30, 2018 and 2017, respectively.
(a)Primarily reflects the impact of net gains and losses on Generation’s economic hedging activities.
(b)Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.

Table of Contents

(c)Reflects the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.
(d)
Primarily reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2017, reflects costs related to the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs. In 2018, reflects costs related to the PHI acquisition.
(e)Primarily reflects a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.
(f)Primarily reflects charges to earnings related to the impairment of the EGTP assets held for sale in 2017, and in 2018 the impairment of certain wind projects at Generation.
(g)Primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the Three Mile Island nuclear facility in 2017. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO and accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the Three Mile Island nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business.
(h)Primarily represents severance and reorganization costs related to a cost management program.
(i)Represents the excess fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.
(j)Reflects adjustments to income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.
(k)Reflects the changes in the Illinois and District of Columbia statutory tax rate and changes in forecasted apportionment in 2017. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the Tax Cuts and Jobs Act (TCJA) and changes in forecasted apportionment.
(l)Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI’s unregulated business interests.
(m)Reflects elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.
(n)Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units in 2017. In 2018, reflects an increase at Pepco related primarily to asbestos identified at its Buzzard Point property.
Significant 2018 Transactions and Developments
Regulatory Implications of the Tax Cuts and Jobs Act (TCJA)
The Utility Registrants have made filings with their respective State regulators to begin passing back to customers the ongoing annual tax savings resulting from the TCJA. The amounts being proposed to be passed back to customers reflect the annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. The Utility Registrants have identified over $675 million in ongoing annual savings to be returned to customers related to TCJA from their distribution utility operations. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Early Plant Retirements
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in 2018. On September 17, 2018, Oyster Creek permanently ceased generation operations. Because of the decision to early retire Oyster Creek in 2018, Exelon and Generation recognized certain one-time charges in the first quarter of 2018 related to a materials and supplies inventory reserve adjustment, employee-related costs and construction work-in-progress impairments, among other items.
On July 31, 2018, Generation entered into an agreement with Holtec International and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the sale and decommissioning of Oyster Creek. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
On May 30, 2017, Generation announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The plant is currently committed to operate through May 2019.
As a result of the early nuclear plant retirement decisions at Oyster Creek and TMI, Exelon and Generation will also recognize annual incremental non-cash charges to earnings stemming from

Table of Contents

shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions were also recorded. The following table summarizes the actual incremental non-cash expense item incurred in 2018 and the estimated amount of incremental non-cash expense items expected to be incurred in 2018 and 2019 due to the early retirement decisions.
 Actual 
Projected(a)
Income statement expense (pre-tax)Nine Months Ended September 30, 2018 2018 2019
Depreciation and amortization(b)
     
         Accelerated depreciation(c)
$441
 $550
 $330
         Accelerated nuclear fuel amortization52
 55
 5
Operating and maintenance(d)
32
 35
 5
Total$525
 $640
 $340
_________
(a)Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.
(b)Reflects incremental accelerated depreciation and amortization for TMI and Oyster Creek for the nine months ended September 30, 2018. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018.
(c)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(d)Primarily includes materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments.
In 2017, PSEG also made public financial challenges facing its New Jersey nuclear plants including Salem, of which Generation owns a 42.59% ownership interest. Although Salem is committed to operate through May 2021, the plant faces continued economic challenges and PSEG, as the operator of the plant, is exploring all options.
On May 23, 2018, the Governor of New Jersey signed new legislation, which became effective immediately, that will establish a ZEC program providing compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the new legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. The NJBPU has 180 days from the effective date to establish procedures for implementation of the ZEC program and 330 days from the effective date to determine which nuclear power plants are selected to receive ZECs under the program. Assuming the successful implementation of the New Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk of earlier retirement for Salem. See Note 6 — Regulatory Matters and Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information on the new legislation and the New Jersey ZEC program.
On March 29, 2018, based on ISO-NE capacity auction results for the 2021 - 2022 planning year in which Mystic Unit 9 did not clear, Generation announced it had formally notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets on June 1, 2022 absent any interim and long-term solutions for reliability and regional fuel security. The ISO-NE announced that it would take a three-step approach to fuel security. First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel security for the 2022 - 2024 planning years.  Second, ISO-NE planned to file tariff revisions to allow it to retain other resources for fuel security in the capacity market if necessary in the future. Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot

Table of Contents

recover future operating costs including the cost of procuring fuel. As a result of these developments, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group during the first quarter of 2018 and no impairment charge was required.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024.
On July 2, 2018, FERC issued an order denying ISO-NE's May 1, 2018, waiver request on procedural grounds but accepting ISO-NE's conclusions that retirement of Mystic Units 8 and 9 could cause a violation of mandatory reliability standards as soon as 2022. Accordingly, FERC ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address demonstrated fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. FERC also extended the deadline by which Generation must make a retirement decision for Mystic Units 8 and 9 to January 4, 2019. On August 31, 2018, ISO-NE filed a compliance filing in response to FERC's July 2, 2018 order proposing short-term tariff changes to permit it to retain a resource for fuel security reliability reasons. A number of parties, including Generation, have submitted comments on the proposal, which is pending before FERC.
On July 13, 2018, FERC issued an order accepting the cost-of-service agreement for filing, making findings on certain issues and establishing hearing procedures on an expedited schedule. Further developments such as the failure of ISO-NE to adopt interim and long-term solutions for reliability and fuel security could potentially result in future impairments of the New England asset group, which could be material. See Note 7 — Impairment of Long-Lived Assets and Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Illinois ZEC Procurement
Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue. Winning bidders are entitled to compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. During the three months ended September 30, 2018, Generation recognized revenue of $61 million. During the nine months ended September 30, 2018, Generation recognized revenue of $315 million, of which $150 million related to ZECs generated from June 1, 2017 through December 31, 2017.
Westinghouse Electric Company LLC Bankruptcy
On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. On January 4, 2018, Westinghouse announced its agreement to be purchased by an affiliate of Brookfield Business Partners, LLC (Brookfield) for approximately $4.6 billion. On March 28, 2018, the Bankruptcy Court entered an Order confirming the Debtor's Second Amended Joint Plan of Reorganization which provides for the transaction with Brookfield. The transaction closed on August 1, 2018. Exelon had contracts with Westinghouse primarily related to Generation's purchase of nuclear fuel, as well as a variety of services and equipment purchases associated with the operation and maintenance of nuclear generating stations. In conjunction with the confirmation hearing, Exelon had filed a reservation of rights regarding reorganizing Westinghouse's assumption of all Exelon contracts. Exelon reached an agreement with Brookfield, and all Exelon contracts were assumed by Brookfield on the closing date.

Table of Contents

Utility Rates and Base Rate Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2018. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
Registrant Jurisdiction 
Approved Revenue Requirement Increase (Decrease)
(in millions)
 Approved Return on Equity Completion Date Rate Effective Date
Pepco District of Columbia (Electric) $(24) 9.525% August 9, 2018 August 13, 2018
Pepco Maryland (Electric) $(15) 9.5% May 31, 2018 June 1, 2018
DPL Delaware (Electric) $(7) 9.7% August 21, 2018 March 17, 2018
DPL Maryland (Electric) $13
 9.5% February 9, 2018 September 5, 2018
Pending Distribution Base Rate Case Proceedings
Registrant Jurisdiction 
Requested or Settlement Revenue Requirement Increase (Decrease)
(in millions)
 Requested or Settlement Return on Equity Filing or Settlement Date Expected Completion Timing
ComEd Illinois (Electric) $(23) 8.69% April 16, 2018 Fourth quarter 2018
PECO Pennsylvania (Electric) $25
 
N/A(a)

 August 28, 2018 Fourth quarter 2018
BGE Maryland (Natural Gas) $61
 10.50% June 8, 2018 (Updated on August 24, 2018 and October 12, 2018) First quarter 2019
DPL Delaware (Natural Gas) $(4) 9.70% September 7, 2018 (Updated on October 2, 2018) Fourth quarter 2018
ACE New Jersey (Electric) $109
 10.10% August 21, 2018 Third quarter 2019
__________
(a)No overall ROE was specified in the partial settlement agreement.
See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these base rate case proceedings.

Table of Contents

Transmission Formula Rate
The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2018 annual electric transmission formula rate updates.
 2018
Annual Transmission Updates(a)(b)
ComEd BGE Pepco DPL ACE
Initial revenue requirement (decrease) increase$(44) $10
 $6
 $14
 $4
Annual reconciliation increase (decrease)18
 4
 2
 13
 (4)
Dedicated facilities increase(c)
—
 12
 —
 —
 —
Total revenue requirement (decrease) increase$(26) $26
 $8
 $27
 $—
          
Allowed return on rate base(d)
8.32% 7.61% 7.82% 7.29% 8.02%
Allowed ROE(e)
11.50% 10.50% 10.50% 10.50% 10.50%
_________
(a)All rates are effective June 2018, subject to review by the FERC and other parties, which is due by fourth quarter 2018.
(b)The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA.  See further discussion above. 
(c)BGE's transmission revenues include a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to a specifically designated load by BGE.
(d)Represents the weighted average debt and equity return on transmission rate bases.
(e)As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization.
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the final outcome of this proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a revenue decrease of $6 million. The revenue decrease of $6 million included an approximately $20 million reduction as a result of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.


Table of Contents

Winter Storm-Related Costs
During March 2018 there were powerful nor'easter storms that brought a mix of heavy snow, ice and high sustained winds and gusts to the region that interrupted electric service delivery to customers in PECO's, BGE's, Pepco's, DPL's and ACE's service territories. Restoration efforts included significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies, which resulted in incremental operating and maintenance expense and incremental capital expenditures in the first quarter of 2018 for PECO, BGE, PHI, Pepco, DPL and ACE. In addition, PHI, Pepco, DPL and ACE recorded regulatory assets for amounts that are probable of recovery through customer rates. The impacts recorded by the Registrants for the nine months ended September 30, 2018 are presented below:
   (in millions)
 Customer Outages Incremental Operating & Maintenance Incremental Capital Expenditures
Exelon1,727,000
 $88
(b) 
$89
PECO750,000
 53
 35
BGE425,000
 31
 15
PHI(a)
552,000
 4
(b) 
39
Pepco182,000
 2
(b) 
4
DPL138,000
 2
(b) 
4
ACE232,000
 —
(b) 
31
________
(a)PHI reflects the consolidated customer outages, incremental operating & maintenance and incremental capital expenditures of Pepco, DPL and ACE.
(b)Excludes amounts that were deferred and recognized as regulatory assets at Exelon, PHI, Pepco, DPL and ACE of $28 million, $28 million, $7 million, $1 million and $20 million, respectively.
Exelon’s Strategy and Outlook for 2018 and Beyond
Exelon’s value proposition and competitive advantage come from its scope and its core strengths of operational excellence and financial discipline. Exelon leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition:
The Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and in long-term, contracted assets and to reduce debt.
Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart meter

Table of Contents

technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon's Board of Directors has approved a dividend policy providing a raise of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS of the Exelon 2017 Form 10-K for additional information regarding market and financial factors.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy.  In August 2015, Exelon announced a cost management program focused on cost savings of approximately $400 million at BSC and Generation, which was fully realized in 2018.  Approximately 75% of the savings were related to Generation, with the remaining amount related to the Utility Registrants. In November 2017, Exelon announced a commitment for an additional $250 million of cost savings, primarily at Generation, to be achieved by 2020. In November 2018, Exelon announced the elimination of an approximately additional $200 million of annual ongoing costs, through initiatives primarily at Generation and BSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The PHI merger 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 $28 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 $11 billion by the end of 2022. 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.

Table of Contents

See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements Exelon 2017 Form 10-K 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 its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.
Liquidity Considerations
Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
Exelon Corporate, 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 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion.
For additional information regarding the Registrants' liquidity for the nine months ended September 30, 2018, see Liquidity and Capital Resources discussion below.
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 debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.

Table of Contents

Other Key Business Drivers and Management Strategies
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
FERC Inquiry on Resiliency
On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On January 8, 2018, FERC issued an order terminating the rulemaking docket that it initiated to address the proposed rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, FERC initiated a new proceeding to consider resiliency challenges to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. FERC directed each RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Thereafter, interested parties submitted reply comments on May 9, 2018, and a few parties submitted further replies. Exelon has been and will continue to be an active participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs
PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new gas-fired resources.
On January 9, 2017, EPSA filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. A similar complaint also against PJM was filed at FERC on May 31, 2018. These complaints generally allege that the relevant MOPR should be expanded to also apply to existing resources including those receiving ZEC compensation under the New York CES and Illinois ZES programs. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental agenciesattribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS programs that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation (Quad Cities, Ginna, Fitzpatrick and Nine Mile Point), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in future capacity auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any mitigation of these generating resources could have a material effect on Exelon’s

Table of Contents

and Generation’s future cash flows and results of operations. The same risk would also exist for the Salem facility if Salem is selected as an eligible facility under the NJ ZEC program.
Separately, PJM submitted two proposed alternative capacity market reforms in April 2018 for FERC’s consideration. PJM argued that either alternative will resolve any conflict between state policy support for certain resources and the need to ensure reasonable prices for non-supported resources. The first alternative was to implement a twice-run capacity clearing mechanism (known as the repricing proposal) and, if not acceptable to FERC, a second alternative that would expand the existing MOPR to both new and existing generating resources, subject to certain exemptions (known as MOPREx).
In June 2018, FERC issued an order rejecting both of PJM’s proposed alternatives, finding both to be unjust and unreasonable. In the same order, FERC also addressed one of the MOPR complaints involving PJM and concluded based on that complaint and PJM’s filing that PJM’s existing tariff allows resources receiving out-of-market support to affect capacity prices in a manner that will cause unjust and unreasonable and unduly discriminatory rates in PJM regardless of the intent motivating the support. FERC suggested that modifying two elements of PJM’s existing tariff could produce a just and reasonable replacement and asked for initial comments on its proposal by August 28, 2018, later extended to October 2, 2018. First, FERC found that an expansion of the current MOPR mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or others,REC compensation, could protect the capacity markets from unwanted price suppression. Second, FERC preliminarily found that a modified version of PJM’s existing Fixed Resource Requirement (FRR) option could enable state subsidized resources and a corresponding amount of load to be removed from the capacity market, thereby alleviating their price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through mechanisms other than through PJM’s existing market mechanism. FERC established March 21, 2016 as the refund effective date and also allowed PJM to delay its next capacity auction from May 2019 to August 2019 to allow parties time to develop and file proposals in the FERC proceeding, FERC time to determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates, environmental organizations and other nuclear generators, submitted shared principles supporting a workable new FRR mechanism (as suggested by FERC) and detailing how such a mechanism should be implemented. Exelon also submitted individual comments covering matters not addressed in the shared principles. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. It is too early to predict the final outcome of each of these proceedings or their potential financial impact, if any, on Exelon or Generation.
Section 232 Uranium Petition
On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce (DOC) seeking relief under Section 232 of the Trade Expansion Act of 1962 (as amended) from imports of uranium products, alleging that these imports threaten national security (the Petition). The Trade Expansion Act of 1962 (the Act) was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.
On July 18, 2018, the Secretary announced that the DOC has initiated an investigation in response to the petition. The Secretary has 270 days to prepare and submit a report to President Trump, who then has 90 days to act on the Secretary's recommendations. Exelon and Generation cannot currently predict the outcome of this investigation. The relief sought by the petitioners would require U.S. nuclear reactors

Table of Contents

to purchase at least 25% of their uranium needs from domestic mines over the next 10 years, although the DOC will make an independent determination regarding an appropriate remedy should it find that imports impair national security. It is reasonably possible that if this petition is successful the resulting increase in nuclear fuel costs in future periods could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.
Potential DOE Order Pursuant to Defense Production Act and Federal Power Act
The DOE is considering an Order directing ISOs, for 24 months, to purchase electric energy or generation capacity from a designated list of coal and nuclear generation facilities. Based on a draft memorandum, the Order would be pursuant to DOE's authorities under the Defense Production Act and Federal Power Act, and would forestall any further actions towards retiring, decommissioning, or deactivating coal and nuclear facilities during the term of the Order. The Order would emphasize the importance of grid resiliency, in addition to grid reliability, noting that fuel security and diversity are critical components of resiliency. The DOE recognizes that the underlying economic and regulatory issues are complex and will take time resolve. The Order's 24-month duration would enable DOE to conduct additional analyses to gain a detailed understanding of location-specific vulnerabilities in U.S. energy delivery systems, while preserving certain generation facilities. Exelon has been and will continue to be an active participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
Energy Demand
Modest economic growth partially offset by energy efficiency initiatives is resulting in relatively flat load growth in electricity for the Utility Registrants. ComEd, PECO, BGE, Pepco, DPL and ACE are projecting load volumes to increase by 0.5%, 1.7%, 0.7%, 0.2%, 1.3% and 4.3% respectively, in 2018 compared to 2017.
Retail Competition
Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. Forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.
Strategic Policy Alignment
As part of its strategic business planning process, Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices and the impacts of hypothetical credit downgrades.
Exelon's board of directors declared first quarter 2018 dividends of $0.345 per share on Exelon's common stock. The first quarter 2018 dividend was paid on March 9, 2018. The dividend increased from the fourth quarter 2017 amount to reflect the Board's decision to raise Exelon's dividend 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
Exelon's board of directors declared second quarter 2018 dividends of $0.345 per share on Exelon's common stock and was paid on June 8, 2018.
Exelon's board of directors declared third quarter 2018 dividends of $0.345 per share on Exelon's common stock and was paid on September 10, 2018.

Table of Contents

Exelon's board of directors declared fourth quarter 2018 dividends of $0.345 per share on Exelon's common stock and is payable on December 10, 2018.
All future quarterly dividends require approval by Exelon's Board of Directors.
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 2018 and 2019. 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 September 30, 2018, the percentage of expected generation hedged is 98%-101%, 82%-85% and 48%-51% for 2018, 2019, and 2020 respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.
Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 59% of Generation’s uranium concentrate requirements from 2018 through 2022 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 positions.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Environmental Legislative and Regulatory Developments
Exelon was actively involved in the Obama Administration’s development and implementation of environmental regulations for the electric industry, in pursuit of its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil fuel plants.

Table of Contents

Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.
In particular, the Administration has targeted certain existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings and withdrew all technical support documents supporting the calculation. Other regulations that are under review include the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the Coal Combustion Residuals rule. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.
Air Quality
Mercury and Air Toxics Standard Rule (MATS). On December 16, 2011, the EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. The initial compliance deadline to meet the new standards was April 16, 2015; however, facilities may have been granted an additional one or two-year extension in limited cases. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether such costsit is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court to take further action consistent with the U.S. Supreme Court’s opinion on this single issue. On April 27, 2017, the D.C. Circuit granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. Notwithstanding the Court’s order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule.
Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be recoverable from third parties, including customers.remanded to the EPA. On October 10, 2017, EPA issued a proposed rule to repeal the CPP in its entirety, based on a proposed change in the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. The EPA has also issued an advance notice of proposed rulemaking to solicit information on systems of emission reduction that are in accord with the Agency’s proposed revised legal interpretation; namely, only by regulating emission reductions that can be implemented at and to individual sources.

Table of Contents

2015 Ozone National Ambient Air Quality Standards (NAAQS). On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. Concurrent with its review, the Agency issued several rounds of final ozone designations for the 2015 ozone NAAQS in December 2017 and April 2018. On August 1, 2018, EPA filed a status report to the Court that indicated Agency does not intend to revise or repeal the 2015 ozone standard at this time. Subsequently the Court ordered the case reactivated.
Primary SO2 National Ambient Air Quality Standards (NAAQS). On June 8, 2018, the EPA proposed to maintain the primary NAAQS for sulfur dioxide (SO2) at the same level and averaging time as was finalized by EPA in its 2010 SO2 NAAQS update. The schedule for completing this review is established by a consent decree, which sets January 28, 2019 as the deadline for signature on a final decision notice.
Climate Change. Exelon supports comprehensive climate change legislation or regulation which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In June 2018, Exelon joined the Climate Leadership Council, which advocates for a revenue neutral carbon tax and dividend program. In the absence of Federal legislation, the EPA has been reviewing the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the international regulation of GHG emissions pursuant to the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). See ITEM 1. BUSINESS, "Air Quality" of the Exelon 2017 Form 10-K for additional information.
Water QualityLitigation and Regulatory Matters
Benning Road Site NPDES Permit Limit Exceedances. Pepco holdsPHI Merger (Exelon and PHI)
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 Exelon and PHI merger. The Circuit Court judge issued an NPDES permit issuedorder 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 EPA withthe OPC, the Sierra Club, CCAN and Public Citizen, Inc. On January 19, 2016, the OPC filed a July 19, 2009 effective date,notice of appeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed notices of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment that the MDPSC did not err in approving the merger. The OPC and Sierra Club filed petitions seeking further review in the Court of Appeals of Maryland, which authorizes discharges fromis the Benning Road service facility. The 2009 permit forhighest court in Maryland. On June 21, 2017, the first time imposed numerical limits on the allowable concentrationCourt 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 allAppeals granted discretionary review of the numerical limits for all metals.
January 27, 2017 decision by the Maryland Court of Special Appeals. The 2009 permit remains in effect pending EPA’s action onMaryland Court of Appeals will review the Pepco renewal application, including resolution ofOPC argument that the stormwater compliance issues. On October 30, 2015, EPAMDPSC did not properly consider the acquisition premium paid to PHI shareholders under Maryland’s merger approval standard and the Sierra Club’s argument that the merger would harm the renewable and distributed generation markets. The two lower courts examining these issues rejected these arguments, which Exelon believes are without merit. All briefs have been filed a Clean Water Act civil enforcement action against Pepco in federal district court, and in March 2016oral arguments were presented to the court granted a motion byon October 10, 2017. On August 29, 2018, the Anacostia Riverkeeper to intervene in this case as a plaintiff along with EPA. Since 2009 Pepco has installed runoff mitigation measuresMaryland Court of Appeals affirmed the MDPSC's May 2015 Order approving the merger of Exelon and implemented new operating procedures to comply with regulations. In January 2017,PHI. This concluded 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 improvementsfinal legal challenge to the stormwater management system. On May 19, 2017,merger of Exelon and PHI.
Asbestos Personal Injury Claims (Exelon, Generation, PECO and ComEd)
Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the Consent Decree was enteredestimated legal costs associated with the Court and became final. The Civil Penalty assessed under the Consent Decree of $1.6 million was paid on June 5, 2017 and other requirements of the Decree are now being implemented.handling these matters, which could be material.
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. 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. OnAt September 30, 2011,2018 and December 31, 2017, Generation had recorded estimated liabilities of approximately $80 million and $78 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2018, approximately $24 million of this amount related to 241 open claims presented to Generation, while the PRPs submittedremaining $56 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the supplemental feasibility studynumber of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study. This further analysis has focused on a partial excavation remedial option. The PRPs have provided a draft Remedial Investigation and Feasibility Study (RI/FS) report to the EPA for its review and comment. The final RI/FS will form the basis of EPA’s selection of a remedy from among the alternatives of a landfill cover, and partial or complete excavation. The EPA has advised the PRPs that the EPA announcement of the proposed remedy will take place in the first quarter of 2018. Thereafter, the EPA will select a final remedy and seek to 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 on going.
The estimated cost of the landfill cover remedy (taking into account the current EPA technical requirements incorporated in the third quarter 2017) is approximately $110 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 a landfill cover, which is included in the table above. 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. 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.liabilities are necessary.

159
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

During December 2015, the EPA took two actions relatedThere is a reasonable possibility that Exelon may have additional exposure 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 firesestimated future asbestos-related bodily injury claims 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 areasexcess 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 foramount accrued 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 matterincreases could have a material unfavorable impact on Exelon's, Generation's and Exelon's future results of operations and cash flows. Finally, one of the other PRPs, the landfill owner and operator of the adjacent landfill, has indicated that it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Generation and Exelon do not possess sufficient information to assess this claim and are therefore unable to determine the impact on their futurePECO's financial conditions, results of operations and cash flows.
City of Everett Tax Increment Financing Agreement (Exelon and Generation)
On February 2, 2016,April 10, 2017, the U.S. Senate passedCity of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a billthree-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to transfer remediation authoritydecertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the West Lake Landfill fromperiod of the EPATIF Agreement. Generation vigorously contested the City’s claims before the EACC and will continue to the U.S. Army Corps of Engineers, under the Formerly Utilized Sites Remedial Action Program (FUSRAP). The legislation was not passeddo so in the U.S. House of Representatives, and would therefore require reintroduction in the Senate for consideration in the current session of Congress. Should such proposed legislation ultimately become law, it would be subjectMassachusetts Superior Court proceeding. Generation continues to annual funding appropriations in the U.S. Budget. Remediation under FUSRAP would not alter the liability of the PRPs, but would likely 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 foundbelieve 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 DOJCity’s claim lacks merit. Accordingly, Generation has not yet formally advised the PRPsrecorded a liability for payment resulting from such a revocation, nor can Generation estimate a reasonably possible range 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 2018 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 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,loss, if any, associated with any such revocation. Further, it is reasonably possible that Exelon wouldproperty taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2019, could be financially responsible duematerial to its indemnification responsibilitiesGeneration’s results of Cotter described above. operations and cash flows.
General (All Registrants)
The court has dismissed a number of lawsuits,Registrants are involved in various other litigation matters that are being defended and is expected to dismiss additional lawsuits based on a recent ruling. Pre-trial motions and discovery are proceedinghandled in the remaining casesordinary course of business. The assessment of whether a loss is probable or reasonably possible, and a pre-trial scheduling order has been filed withwhether the court. At this stage of the litigation, Generation and ComEd cannot estimateloss or a range of loss if any.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.
68th Street Dump.   InIncome Taxes
See Note 12 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 the 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 resultsale 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 PRPsfossil generating assets.

160
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

with respect to investigation18. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about the site became effective. The settlement requiresRegistrants’ Consolidated Statements of Operations and Comprehensive Income for the PRPs, over the course of several years, to identify contamination at the sitethree and recommend clean-up options. The PRPs submitted their investigation of the range of clean-up options in the first quarter of 2011. Onnine months ended September 30, 2013, EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by EPA is consistent with the PRPs estimated range of costs noted above. In July, 2017 the PRPs2018 and EPA finalized the terms of a Consent Decree which has been executed by the Parties and lodged with the U.S. District Court. After publication in the Federal Register there will be a 30-day public comment period after which it is anticipated it will be approved by the Court without any significant change in the costs for cleanup, Generation has elected to be a non-performing cash-out party and following payment of the allocated cost for its share of the clean-up. Generation will have no remaining liability at the site, except for unknown conditions that could manifest themselves after the settlement. The cash-out payment is included in the table above and is immaterial to the Generation and Exelon financial statements.2017.
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 $1 million which has been fully reserved and included in the table above as of September 30, 2017.
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 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. Although the ultimate outcome of this proceeding is uncertain based on the information complied to date, BGE has developed an estimate of the range of the probable liability; such costs would be shared by the 4 identified PRPs. BGE has accrued an appropriate reserve for its share of the estimated liabilities that is included it in the table above. It is possible, however, that final resolution of this matter could have a material, unfavorable impact on 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 in June 2015. In November 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 in May 2017 BGE completed the additional work requested by MDE.  All the offsite sample testing produced results that were below the cleanup action level established by MDE and no further investigation is required. MDE has provided BGE with the required clean-up levels for the on-site contamination and BGE is moving forward with the necessary remediation as directed by MDE. BGE has established what it believes is an appropriate reserve based upon the information available to date, and this amount is included in the table above.  As the remediation proceeds, it is possible that additional reserves could be established, in amounts that could be material to BGE.
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. Additionally, legislation was passed during the 2017 Maryland General Assembly session that should further support BGE’s recovery of its clean-up costs.
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
 Three Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on decommissioning trust funds(a)
                 
Regulatory agreement units$214
 $214
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units58
 58
 —
 —
 —
 —
 —
 —
 —
Net unrealized (losses) gains on decommissioning trust funds                 
Regulatory agreement units(66) (66) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units72
 72
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                 
Zion Station decommissioning(9) (9) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(110) (110) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities159
 159
 —
 $—
 —

—
 —
 —
 —
Investment income9
 5
 —
 —
 —
 2
 1
 1
 —
Interest income related to uncertain income tax positions1
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity16
 —
 4
 1
 5
 6
 6
 —
 —
Non-service net periodic benefit cost(12) —
 —
 —
 —
 —
 —
 —
 —
Other21
 15
 3
 1
 —
 3
 —
 1
 1
Other, net$194

$179

$7

2

$5

$11

$7

$2

$1

161
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a Remediation Investigation (RI)/ Feasibility Study (FS) for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. Pursuant to Exelon's March 23, 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation. On July 1, 2017, Pepco Energy Services was merged into Constellation New Energy, a subsidiary of Generation.
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 Generation will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Generation will then proceed to develop an FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the RI and FS, and approval by the DOEE, by June 2018.
 Nine Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on decommissioning trust funds(a)
                 
Regulatory agreement units$476
 $476
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units257
 257
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on decommissioning trust funds                 
Regulatory agreement units(335) (335) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units(143) (143) —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                 
Zion Station decommissioning(7) (7) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(110) (110) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities138
 138
 —
 —
 —
 —

—
 —
 —
Investment income19
 12
 —
 —
 —
 3
 1
 1
 —
Interest income related to uncertain income tax positions5
 1
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity47
 —
 12
 3
 13
 19
 17
 2
 —
Non-service net periodic benefit cost(33) —
 —
 —
 —
 —
 —
 —
 —
Other36
 13
 9
 1
 1
 11
 5
 4
 2
Other, net$212

$164

$21

$4

$14
 $33

$23

$7

$2
Upon DOEE’s approval of the final RI and FS Reports, Pepco and Generation will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.
PHI, Pepco and Generation have determined that a loss associated with this matter for PHI, Pepco and Generation 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 accruals could be established in amounts that could be material to PHI and Pepco. 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 Generation, DOEE and certain federal agencies have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-D.C. boundary line to the confluence of the Anacostia and Potomac Rivers. In March 2016, DOEE released a draft of the river-wide RI Report for public review and comment. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a “Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning 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 and that a feasibility study of potential remedies is expected to be completed in December 2017. A proposed remedy for the clean-up of sediments in this section of the river is expected to be released for public comment in February 2018 and the DOEE has targeted June 2018 as the date for remedy selection. 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.
 Three Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on decommissioning trust funds(a)
                 
Regulatory agreement units$159
 $159
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units59
 59
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on decommissioning trust funds                 
Regulatory agreement units44
 44
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units111
 111
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                 
Zion Station decommissioning(4) (4) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(161) (161) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities208
 208
 —
 —
 —

—

—
 —
 —
Investment income2
 1
 —
 —
 —
 1
 1
 —
 —
Interest expense related to uncertain income tax positions4
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity17
 —
 2
 2
 4
 9
 6
 2
 1
Non-service net periodic benefit cost(27) —
 —
 —
 —
 —
 —
 —
 —
Other6
 —
 3
 —
 —
 3
 —
 2
 —
Other, net$210

$209

$5

$2

$4
 $13

$7

$4

$1

162
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Conectiv Energy Wholesale Power Generation Sites. In July 2010, PHI sold
 Nine Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on decommissioning trust funds(a)
                 
Regulatory agreement units$439
 $439
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units165
 165
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on decommissioning trust funds                 
Regulatory agreement units253
 253
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units347
 347
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                 
Zion Station decommissioning(5) (5) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(558) (558) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities641
 641
 —
 —
 —
 —

—
 —
 —
Investment income6
 4
 —
 —
 —
 2
 1
 —
 —
Interest income related to uncertain income tax positions3
 —
 —
 —
 —
 —
 —
 —
 —
Penalty income related to uncertain income tax positions2
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity51
 —
 6
 6
 12
 27
 17
 5
 5
Non-service net periodic benefit cost(82) —
 —
 —
 —
 —
 —
 —
 —
Other22
 3
 8
 —
 —
 11
 4
 5
 1
Other, net$643

$648

$14

$6

$12
 $40

$22
 $10
 $6
_________
(a)Includes investment income and realized gains and losses on sales of investments of the trust funds.
(b)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 15 — Asset Retirement Obligations of the Exelon 2017 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
The following utility taxes are included in revenues and expenses for the wholesale power generation businessthree and nine months ended September 30, 2018 and 2017. Generation’s utility tax expense represents gross receipts tax related to its retail operations, and the Utility Registrants' utility tax expense represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection 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 to Calpine triggered an obligationutility taxes from customers is recorded in revenues on the partRegistrants’ Consolidated Statements of Conectiv EnergyOperations and Comprehensive Income.
 Three Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$253

$32

$67

$39

$23
 $92
 $87

$5

$—
 Nine Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$705

$92

$188

$102

$70
 $253
 $238

$15

$—
 Three Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$245

$35

$65

$35

$22
 $88
 $83

$5

$—

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

 Nine Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$682

$97

$181

$95

$69
 $240
 $226

$14

$—
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the nine months ended September 30, 2018 and 2017.
 Nine Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization and accretion                 
Property, plant and equipment(a)
$2,829
 $1,347
 $613
 $204
 $249
 $355
 $161
 $97
 $70
Amortization of regulatory assets(a)
412
 —
 83
 20
 109
 200
 125
 38
 37
Amortization of intangible assets, net(a)
43
 36
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
8
 8
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
852
 852
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
367
 365
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$4,511

$2,608

$696

$224

$358
 $555
 $286

$135

$107
 Nine Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization and accretion                 
Property, plant and equipment(a)
$2,416
 $1,010
 $579
 $194
 $233
 $342
 $153
 $92
 $66
Amortization of regulatory assets(a)
355
 —
 52
 19
 115
 169
 89
 32
 47
Amortization of intangible assets, net(a)
43
 36
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
19
 19
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
816
 816
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
350
 350
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$3,999

$2,231

$631

$213

$348
 $511
 $242

$124

$113
_________
(a)Included in Depreciation and amortization on the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(b)Included in Operating revenues or Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(d)Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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

 Nine Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:                 
Pension and non-pension postretirement benefit costs$435
 $151
 $133
 $14
 $43
 $51
 $10
 $5
 $10
Loss (gain) from equity method investments22
 23
 —
 —
 —
 (1) —
 —
 —
Provision for uncollectible accounts133
 38
 30
 25
 6
 32
 12
 6
 14
Stock-based compensation costs64
 —
 —
 —
 —
 —
 —
 —
 —
Other decommissioning-related activity(a)
(39) (39) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
4
 4
 —
 —
 —
 —
 —
 —
 —
Amortization of regulatory asset related to debt costs6
 —
 2
 —
 —
 3
 1
 1
 1
Amortization of rate stabilization deferral—
 —
 —
 —
 —
 —
 —
 —
 —
Amortization of debt fair value adjustment(12) (9) —
 —
 —
 (3) —
 —
 —
Discrete impacts from EIMA and FEJA(c)
27
 —
 27
 —
 —
 —
 —
 —
 —
Amortization of debt costs26
 10
 4
 1
 1
 3
 2
 1
 —
Provision for excess and obsolete inventory15
 13
 2
 —
 —
 —
 —
 —
 —
Long-term incentive plan84
 —
 —
 —
 —
 —
 —
 —
 —
Asset retirement costs20
 —
 —
 —
 —
 20
 22
 (1) (1)
Other19
 (4) (11) 1
 (8) 4
 (5) 4
 —
Total other non-cash operating activities$804

$187

$187

$41

$42
 $109
 $42

$16

$24
Non-cash investing and financing activities:              
(Decrease) increase in capital expenditures not paid$(175) $(226) $(28) $4
 $44
 $54
 $15
 $20
 $16
Increase in PPE related to ARO update67
 47
 4
 —
 1
 15
 12
 2
 1
Dividends on stock compensation4
 —
 —
 —
 —
 —
 —

—
 —
Acquisition of land3
 —
 —
 —
 —
 3
 —
 —
 3

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

 Nine Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:                 
Pension and non-pension postretirement benefit costs$482
 $170
 $131
 $21
 $47
 $72
 $19
 $10
 $10
Loss from equity method investments26
 26
 —
 —
 —
 —
 —
 —
 —
Provision for uncollectible accounts103
 31
 25
 17
 4
 26
 11
 1
 14
Stock-based compensation costs76
 —
 —
 —
 —
 —
 —
 —
 —
Other decommissioning-related activity(a)
(213) (213) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
15
 15
 —
 —
 —
 —
 —
 —
 —
Amortization of regulatory asset related to debt costs7
 —
 3
 1
 —
 3
 1
 1
 1
Amortization of rate stabilization deferral(7) —
 —
 —
 7
 (14) (12) (2) —
Amortization of debt fair value adjustment(13) (9) —
 —
 —
 (4) —
 —
 —
Discrete impacts from EIMA and FEJA (c)
(61) —
 (61) —
 —
 —
 —
 —
 —
Amortization of debt costs57
 33
 3
 1
 1
 1
 1
 —
 —
Provision for excess and obsolete inventory52
 50
 1
 —
 —
 1
 —
 1
 —
Merger-related commitments(d)
—
 —
 —
 —
 —
 (8) (6) (2) —
Severance costs33
 25
 —
 —
 —
 3
 —
 —
 —
Other46
 4
 10
 (2) (7) (14) (6) (3) (4)
Total other non-cash operating activities$603

$132

$112

$38

$52
 $66
 $8

$6

$21
Non-cash investing and financing activities:                 
(Decrease) increase in capital expenditures not paid$(101) $20
 $(79) $(29) $16
 $(6) $7
 $14
 $(18)
Fair value of pension obligation transferred in connection with the FitzPatrick acquisition—
 33
 —
 —
 —
 —
 —
 —
 —
Decrease in PPE related to ARO update(141) (141) —
 —
 —
 —
 —
 —
 —
Indemnification of like-kind exchange tax position(e)
—
 —
 21
 —
 —
 —
 —
 —
 —
Non-cash financing of capital projects16
 16
 —
 —
 —
 —
 —
 —
 —
Dividends on stock compensation5
 —
 —
 —
 —
 —
 —
 —
 —
Dissolution of financing trust due to long-term debt retirement8
 —
 —
 —
 8
 —
 —
 —
 —
Fair value adjustment of long-term debt due to retirement(5) —
 —
 —
 —
 —
 —
 —
 —
_________
(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations of the Exelon 2017 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded in Operating revenues and expenses.
(c)Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 6 — Regulatory Matters for additional information.
(d)
See Note 4 - Mergers, Acquisitions and Dispositions for additional information.
(e)See Note 12 - Income Taxes for additional information on the like-kind exchange tax position.

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

The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to remediate any environmental contaminationthe total of the same amounts in their Consolidated Statements of Cash Flows.
September 30, 2018Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$1,918
 $1,187
 $124
 $102
 $113
 $153
 $12
 $110
 $11
Restricted cash240
 152
 12
 5
 3
 42
 35
 —
 7
Restricted cash included in other long-term assets163
 —
 144
 —
 —
 19
 —
 —
 19
Total cash, cash equivalents and restricted cash$2,321
 $1,339
 $280
 $107
 $116
 $214
 $47
 $110
 $37
December 31, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$898
 $416
 $76
 $271
 $17
 $30
 $5
 $2
 $2
Restricted cash207
 138
 5
 4
 1
 42
 35
 —
 6
Restricted cash included in other long-term assets85
 —
 63
 —
 —
 23
 —
 —
 23
Total cash, cash equivalents and restricted cash$1,190
 $554
 $144
 $275
 $18
 $95
 $40
 $2
 $31
September 30, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$1,203
 $360
 $257
 $330
 $29
 $137
 $117
 $3
 $5
Restricted cash320
 186
 52
 4
 1
 43
 34
 —
 9
Restricted cash included in other long-term assets22
 —
 —
 —
 —
 22
 —
 —
 22
Total cash, cash equivalents and restricted cash$1,545
 $546
 $309
 $334
 $30
 $202
 $151
 $3
 $36
December 31, 2016Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$635
 $290
 $56
 $63
 $23
 $170
 $9
 $46
 $101
Restricted cash253
 158
 2
 4
 24
 43
 33
 —
 9
Restricted cash included in other long-term assets26
 —
 —
 —
 3
 23
 —
 —
 23
Total cash, cash equivalents and restricted cash$914
 $448
 $58
 $67
 $50
 $236
 $42
 $46
 $133
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K. 
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2018 and December 31, 2017.
September 30, 2018Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:                 
Accumulated depreciation and amortization$23,122
(a) 
$12,753
(a)  
$4,557

$3,521

$3,579
 $759
 $3,311

$1,315

$1,121
Accounts receivable:                 
Allowance for uncollectible accounts$354

$112

$93

$61

$22
 $66
 $25

$16

$25

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

December 31, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:                 
Accumulated depreciation and amortization$21,064
(b) 
$11,428
(b) 
$4,269

$3,411

$3,405
 $487
 $3,177

$1,247

$1,066
Accounts receivable:                 
Allowance for uncollectible accounts$322

$114

$73

$56

$24
 $55
 $21

$16

$18
_________
(a)Includes accumulated amortization of nuclear fuel in the reactor core of $3,278 million.
(b)Includes accumulated amortization of nuclear fuel in the reactor core of $3,159 million.
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 one year. 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 $11 million as of September 30, 2018 and December 31, 2017. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2018 and December 31, 2017 of $11 million consists of $3 million and $8 million for medium risk and high risk segments, respectively. See Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K for additional information regarding uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables.
19. 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 nine Conectiv Energy generating facility sitesRegistrants.
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.
The basis for Generation's reportable segments is the integrated management of its electricity business that is located in New Jersey. Under the termsdifferent geographic regions, and largely representative of the sale, Calpine assumed responsibilityfootprints 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.

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

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 AESO, OIESO and the Canadian portion of MISO.
The CODMs for performingExelon and Generation evaluate the ISRA-required remediationperformance 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.

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 paymentthree and nine months ended September 30, 2018 and 2017 is as follows:
Three Months Ended September 30, 2018 and 2017
 
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Operating revenues(c):
               
2018
Competitive businesses electric revenues$4,741
 $—
 —
 $—
 $—
 $—
 $(306) $4,435
Competitive businesses natural gas revenues397
 —
 —
 —
 —
 —
 —
 397
Competitive businesses other revenues140
 —
 —
 —
 —
 —
 (1) 139
Rate-regulated electric revenues—
 1,598
 700
 645
 1,334
 —
 (7) 4,270
Rate-regulated natural gas revenues—
 —
 57
 86
 24
 —
 (5) 162
Shared service and other revenues—
 —
 —
 —
 3
 458
 (461) —
Total operating revenues$5,278
 $1,598
 $757
 $731
 $1,361
 $458
 $(780) $9,403
2017               
Competitive businesses electric revenues$4,041
 $—
 $—
 $—
 $—
 $—
 $(295) $3,746
Competitive businesses natural gas revenues460
 —
 —
 —
 —
 —
 —
 460
Competitive businesses other revenues249
 —
 —
 —
 —
 —
 —
 249
Rate-regulated electric revenues—
 1,571
 662
 658
 1,280
 —
 (7) 4,164
Rate-regulated natural gas revenues—
 —
 53
 80
 18
 —
 (2) 149
Shared service and other revenues—
 —
 —
 —
 12
 446
 (458) —
Total operating revenues$4,750
 $1,571
 $715
 $738
 $1,310
 $446
 $(762) $8,768
Intersegment revenues(d):
               
2018$308
 $4
 $2
 $6
 $3
 $456
 $(779) $—
2017294
 3
 2
 3
 12
 445
 (759) —
Net income (loss):              
2018$300
 $193
 $126
 $63
 $187
 $(69) $—
 $800
2017346
 189
 112
 62
 153
 3
 —
 865
Total assets:              
September 30, 2018$48,207
 $31,119
 $10,621
 $9,541
 $21,957
 $8,418
 $(10,378) $119,485
December 31, 201748,457
 29,726
 10,170
 9,104
 21,247
 8,618
 (10,552) 116,770
                

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

__________
(a)Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the three months ended September 30, 2018 include revenue from sales to PECO of $35 million, sales to BGE of $69 million, sales to Pepco of $46 million, sales to DPL of $26 million and sales to ACE of $10 million in the Mid-Atlantic region, and sales to ComEd of $122 million in the Midwest region, which eliminate upon consolidation. For the three months ended September 30, 2017, intersegment revenues for Generation include revenue from sales to PECO of $31 million, sales to BGE of $98 million, sales to Pepco of $57 million, sales to DPL of $47 million and sales to ACE of $7 million in the Mid-Atlantic region, and sales to ComEd of $54 million in the Midwest region, which eliminate upon consolidation.
(b)Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(c)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 18 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 2018 and 2017.
(d)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.
PHI:
 Pepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHI
Operating revenues(a):
Three Months Ended September 30, 2018           
Rate-regulated electric revenues$628
 $304
 $406
 $—
 $(4) $1,334
Rate-regulated natural gas revenues—
 24
 —
 —
 —
 24
Shared service and other revenues—
 —
 —
 103
 (100) 3
Total operating revenues$628
 $328
 $406
 $103
 $(104) $1,361
Three Months Ended September 30, 2017           
Rate-regulated electric revenues$604
 $309
 $370
 $—
 $(3) $1,280
Rate-regulated natural gas revenues—
 18
 —
 —
 —
 18
Shared service and other revenues—
 —
 —
 12
 —
 12
Total operating revenues$604
 $327
 $370
 $12
 $(3) $1,310
Intersegment revenues:           
Three Months Ended September 30, 2018$2
 $2
 $1
 $103
 $(105) $3
Three Months Ended September 30, 20171
 2
 —
 13
 (4) 12
Net income (loss):           
Three Months Ended September 30, 2018$89
 $33
 $61
 $1
 $3
 $187
Three Months Ended September 30, 201787
 31
 41
 (18) 12
 153
Total assets:           
September 30, 2018$8,199
 $4,601
 $3,694
 $10,763
 $(5,300) $21,957
December 31, 20177,832
 4,357
 3,445
 10,600
 (4,987) 21,247
__________
(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 18 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 2018 and 2017.
(b)Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of all related ISRA compliance costs up to $10 million. Predecessor PHI was obligated to indemnify Calpinerevenue and cash flows are affected by economic factors for any ISRA compliance remediation costs in excessthree months ended September 30, 2018 and 2017. For Generation, the disaggregation of $10 million. According to PHI’s estimates,revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the costsUtility Registrants, the disaggregation of ISRA-required remediation activities atrevenues reflects the 9 generating facility sitestwo primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are in the range of approximately $7 million to $18 million, and predecessor PHI established an appropriate accrual for its share of the estimated clean-up costs. Pursuant to Exelon’s March 2016 acquisition of PHI, the Conectiv Energy legal entity was transferred toconsistent with Generation and the accrualUtility Registrants, but exclude any intercompany revenues.

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

Competitive Business Revenues (Generation):
 Three Months Ended September 30, 2018
 
Revenues from external parties(a)
 Intersegment
revenues
Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$1,397
 $52
 $1,449
 $7
 $1,456
Midwest1,095
 26
 1,121
 (4) 1,117
New England666
 33
 699
 —
 699
New York475
 (6) 469
 —
 469
ERCOT156
 289
 445
 (1) 444
Other Power Regions293
 265
 558
 (45) 513
Total Competitive Businesses Electric Revenues4,082
 659
 4,741
 (43) 4,698
Competitive Businesses Natural Gas Revenues200
 197
 397
 43
 440
Competitive Businesses Other Revenues(c)
130
 10
 140
 —
 140
Total Generation Consolidated Operating Revenues$4,412
 $866
 $5,278
 $—
 $5,278
 Three Months Ended September 30, 2017
 
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$1,397
 $24
 $1,421
 $11
 $1,432
Midwest982
 67
 1,049
 (11) 1,038
New England504
 (22) 482
 (1) 481
New York454
 (21) 433
 (6) 427
ERCOT164
 144
 308
 6
 314
Other Power Regions167
 181
 348
 (13) 335
Total Competitive Businesses Electric Revenues3,668
 373
 4,041
 (14) 4,027
Competitive Businesses Natural Gas Revenues226
 234
 460
 20
 480
Competitive Businesses Other Revenues(c)
207
 42
 249
 (6) 243
Total Generation Consolidated Operating Revenues$4,101
 $649
 $4,750
 $—
 $4,750
__________
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $13 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the three months ended September 30, 2017, unrealized mark-to-market gains of $6 million and $52 million for the three months ended September 30, 2018 and 2017, respectively, and elimination of intersegment revenues.

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

Revenues net of purchased power and fuel expense (Generation):
 Three Months Ended September 30, 2018 Three Months Ended September 30, 2017
 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
Mid-Atlantic$746
 $17
 $763
 $817
 $38
 $855
Midwest763
 5
 768
 697
 —
 697
New England83
 (2) 81
 151
 (6) 145
New York290
 2
 292
 295
 —
 295
ERCOT161
 (63) 98
 229
 (111) 118
Other Power Regions143
 (44) 99
 118
 (50) 68
Total Revenues net of purchased power and fuel for Reportable Segments2,186

(85)
2,101

2,307

(129)
2,178
Other(b)
112
 85
 197
 112
 129
 241
Total Generation Revenues net of purchased power and fuel expense$2,298

$—

$2,298

$2,419

$—

$2,419
__________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $19 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the three months ended September 30, 2017, unrealized mark-to-market gains of $71 million and $73 million for the three months ended September 30, 2018 and 2017, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 - Early Plant Retirements of $18 million and $6 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2018, and 2017, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

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

Electric and Gas Revenue by Customer Class (the Utility Registrants):
 Three Months Ended September 30, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$861
 $458
 $366
 $726
 $306
 $180
 $240
Small commercial & industrial391
 108
 68
 140
 39
 48
 53
Large commercial & industrial131
 64
 117
 303
 230
 25
 48
Public authorities & electric railroads11
 7
 7
 14
 8
 3
 3
Other(a)
212
 59
 91
 156
 47
 47
 63
Total rate-regulated electric revenues(b)
1,606
 696
 649
 1,339
 630
 303
 407
Rate-regulated natural gas revenues             
Residential—
 36
 46
 8
 —
 8
 —
Small commercial & industrial—
 15
 8
 5
 —
 5
 —
Large commercial & industrial—
 —
 17
 2
 —
 2
 —
Transportation—
 5
 —
 3
 —
 3
 —
Other(c)
—
 1
 12
 6
 —
 6
 —
Total rate-regulated natural gas revenues(d)
—
 57
 83
 24
 —
 24
 —
Total rate-regulated revenues from contracts with customers1,606
 753
 732
 1,363
 630
 327
 407
              
Other revenues             
Revenues from alternative revenue programs(15) 1
 (6) (5) (4) —
 (1)
Other rate-regulated electric revenues(e)
7
 3
 4
 3
 2
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 1
 —
 —
 —
 —
Total other revenues(8) 4
 (1) (2) (2) 1
 (1)
Total rate-regulated revenues for reportable segments$1,598
 $757
 $731
 $1,361
 $628
 $328
 $406

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

 Three Months Ended September 30, 2017
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$816
 $434
 $352
 $687
 $291
 $185
 $211
Small commercial & industrial366
 106
 65
 140
 37
 50
 53
Large commercial & industrial119
 59
 114
 288
 211
 28
 49
Public authorities & electric railroads11
 7
 8
 14
 8
 3
 3
Other(a)
235
 53
 85
 147
 52
 43
 54
Total rate-regulated electric revenues(b)
1,547
 659
 624
 1,276
 599
 309
 370
Rate-regulated natural gas revenues             
Residential—
 33
 44
 8
 —
 8
 —
Small commercial & industrial—
 14
 8
 3
 —
 3
 —
Large commercial & industrial—
 —
 19
 1
 —
 1
 —
Transportation—
 5
 —
 3
 —
 3
 —
Other(c)
—
 1
 3
 3
 —
 3
 —
Total rate-regulated natural gas revenues(d)
—
 53
 74
 18
 —
 18
 —
Total rate-regulated revenues from contracts with customers1,547
 712
 698
 1,294
 599
 327
 370
              
Other revenues             
Revenues from alternative revenue programs16
 —
 36
 2
 3
 (1) —
Other rate-regulated electric revenues(e)
8
 3
 3
 3
 2
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 1
 —
 —
 —
 —
Other revenues(f)
—
 —
 —
 11
 —
 —
 —
Total other revenues24
 3
 40
 16
 5
 —
 —
Total rate-regulated revenues for reportable segments$1,571
 $715
 $738
 $1,310
 $604
 $327
 $370
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $4 million, $2 million, $1 million, $3 million, $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the three months ended September 30, 2018 and $3 million, $1 million, $1 million, $1 million $1 million, $2 million and less than $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the three months ended September 30, 2017.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of less than $1 million and $5 million at PECO and BGE, respectively, for the three months ended September 30, 2018 and less than $1 million and $2 million at PECO and BGE, respectively, for the three months ended September 30, 2017.
(e)Includes late payment charge revenues.
(f)Includes operating revenues from affiliates of $11 million at PHI for the three months ended September 30, 2017.

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

Nine Months Ended September 30, 2018 and 2017
 
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Operating revenues(c):
2018               
Competitive businesses electric revenues$13,190
 $—
 $—
 $—
 $—
 $—
 $(969) $12,221
Competitive businesses natural gas revenues1,839
 —
 —
 —
 —
 —
 (8) 1,831
Competitive businesses other revenues339
 —
 —
 —
 —
 —
 (4) 335
Rate-regulated electric revenues—
 4,508
 1,893
 1,850
 3,549
 —
 (34) 11,766
Rate-regulated natural gas revenues—
 —
 382
 519
 129
 —
 (13) 1,017
Shared service and other revenues—
 —
 —
 —
 10
 1,398
 (1,408) —
Total operating revenues$15,368
 $4,508
 $2,275
 $2,369
 $3,688
 $1,398
 $(2,436) $27,170
2017               
Competitive businesses electric revenues$11,514
 $—
 $—
 $—
 $—
 $—
 $(888) $10,626
Competitive businesses natural gas revenues1,807
 —
 —
 —
 —
 —
 —
 1,807
Competitive businesses other revenues522
 —
 —
 —
 —
 —
 —
 522
Rate-regulated electric revenues—
 4,227
 1,802
 1,895
 3,417
 —
 (23) 11,318
Rate-regulated natural gas revenues—
 —
 339
 468
 105
 —
 (6) 906
Shared service and other revenues—
 —
 —
 —
 35
 1,316
 (1,350) 1
Total operating revenues$13,843
 $4,227
 $2,141
 $2,363
 $3,557
 $1,316
 $(2,267) $25,180
Intersegment revenues(d):
               
2018$981
 $23
 $5
 $18
 $11
 $1,392
 $(2,430) $—
2017888
 12
 5
 12
 35
 1,312
 (2,262) 2
Net income (loss):               
2018$667
 $523
 $336
 $242
 $336
 $(125) $—
 $1,979
2017508
 447
 327
 231
 359
 58
 (2) 1,928
__________
(a)Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the nine months ended September 30, 2018 include revenue from sales to PECO of $97 million, sales to BGE of $198 million, sales to Pepco of $143 million, sales to DPL of $103 million and sales to ACE of $21 million in the Mid-Atlantic region, and sales to ComEd of $419 million in the Midwest region, which eliminate upon consolidation. For the nine months ended September 30, 2017, intersegment revenues for Generation include revenue from sales to PECO of $111 million, sales to BGE of $330 million, sales to Pepco of $209 million, sales to DPL of $138 million and sales to ACE of $23 million in the Mid-Atlantic region, and sales to ComEd of $77 million in the Midwest region, which eliminate upon consolidation.
(b)Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(c)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 18 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 2018 and 2017.

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

(d)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.
PHI:
 Pepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHI
Operating revenues(a):
           
Nine Months Ended September 30, 2018           
Rate-regulated electric revenues$1,708
 $872
 $981
 $—
 $(12) $3,549
Rate-regulated natural gas revenues—
 129
 —
 —
 —
 129
Shared service and other revenues—
 —
 —
 326
 (316) 10
Total operating revenues$1,708
 $1,001
 $981
 $326
 $(328) $3,688
Nine Months Ended September 30, 2017           
Rate-regulated electric revenues$1,649
 $866
 $915
 $—
 $(13) $3,417
Rate-regulated natural gas revenues—
 105
 —
 —
 —
 105
Shared service and other revenues—
 —
 —
 37
 (2) 35
Total operating revenues$1,649
 $971
 $915
 $37
 $(15) $3,557
Intersegment revenues:           
Nine Months Ended September 30, 2018$5
 $6
 $2
 $325
 $(327) $11
Nine Months Ended September 30, 20174
 6
 2
 37
 (14) 35
Net income (loss):           
Nine Months Ended September 30, 2018$174
 $90
 $76
 $(15) $11
 $336
Nine Months Ended September 30, 2017188
 107
 77
 (48) 35
 359
__________
(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 18 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 2018 and 2017.
(b)Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors for Predecessor PHI'snine months ended September 30, 2018 and 2017. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants but exclude any intercompany revenues.

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

Competitive Business Revenues (Generation):
 Nine Months Ended September 30, 2018
 
Revenues from external parties(a)
 
Intersegment
Revenues
 
Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$3,971
 $191
 $4,162
 $17
 $4,179
Midwest3,432
 169
 3,601
 (8) 3,593
New England1,943
 87
 2,030
 (4) 2,026
New York1,305
 (37) 1,268
 1
 1,269
ERCOT470
 459
 929
 1
 930
Other Power Regions713
 487
 1,200
 (112) 1,088
Total Competitive Businesses Electric Revenues11,834
 1,356
 13,190
 (105) 13,085
Competitive Businesses Natural Gas Revenues1,016
 823
 1,839
 105
 1,944
Competitive Businesses Other Revenues(c)
385
 (46) 339
 —
 339
Total Generation Consolidated Operating Revenues$13,235
 $2,133
 $15,368
 $—
 $15,368
 Nine Months Ended September 30, 2017
 
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$4,260
 $(53) $4,207
 $15
 $4,222
Midwest2,948
 210
 3,158
 (17) 3,141
New England1,555
 (86) 1,469
 (8) 1,461
New York1,161
 (37) 1,124
 (14) 1,110
ERCOT520
 229
 749
 4
 753
Other Power Regions439
 368
 807
 (28) 779
Total Competitive Businesses Electric Revenues10,883
 631
 11,514
 (48) 11,466
Competitive Businesses Natural Gas Revenues1,237
 570
 1,807
 52
 1,859
Competitive Businesses Other Revenues(c)
588
 (66) 522
 (4) 518
Total Generation Consolidated Operating Revenues$12,708
 $1,135
 $13,843
 $—
 $13,843
__________
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $30 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the nine months ended September 30, 2017, unrealized mark-to-market losses of $96 million and $47 million for the nine months ended September 30, 2018 and 2017, respectively, and elimination of intersegment revenues.

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

Revenues net of purchased power and fuel expense (Generation):
 Nine Months Ended September 30, 2018 Nine Months Ended September 30, 2017
 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
Mid-Atlantic$2,303
 $45
 $2,348
 $2,330
 $81
 $2,411
Midwest2,381
 19
 2,400
 2,129
 11
 2,140
New England310
 (12) 298
 423
 (20) 403
New York832
 9
 841
 708
 (1) 707
ERCOT396
 (180) 216
 446
 (188) 258
Other Power Regions430
 (121) 309
 359
 (139) 220
Total Revenues net of purchased power and fuel expense for Reportable Segments6,652

(240)
6,412

6,395

(256)
6,139
Other(b)
164
 240
 404
 162
 256
 418
Total Generation Revenues net of purchased power and fuel expense$6,816

$—

$6,816

$6,557

$—

$6,557
__________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $41 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the nine months ended September 30, 2017, unrealized mark-to-market losses of $104 million and $161 million for the nine months ended September 30, 2018 and 2017, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 - Early Plant Retirements of $53 million and $8 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2018 and 2017, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

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

Electric and Gas Revenue by Customer Class (the Utility Registrants):
 Nine Months Ended September 30, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$2,277
 $1,199
 $1,054
 $1,839
 $792
 $513
 $534
Small commercial & industrial1,132
 306
 196
 370
 104
 138
 128
Large commercial & industrial411
 174
 325
 845
 632
 74
 139
Public authorities & electric railroads36
 21
 21
 44
 24
 10
 10
Other(a)
656
 181
 246
 446
 145
 129
 174
Total rate-regulated electric revenues(b)
4,512
 1,881
 1,842
 3,544
 1,697
 864
 985
Rate-regulated natural gas revenues             
Residential—
 259
 345
 68
 —
 68
 —
Small commercial & industrial—
 102
 55
 31
 —
 31
 —
Large commercial & industrial—
 1
 88
 7
 —
 7
 —
Transportation—
 16
 —
 12
 —
 12
 —
Other(c)
—
 4
 49
 11
 —
 11
 —
Total rate-regulated natural gas revenues(d)
—
 382
 537
 129
 —
 129
 —
Total rate-regulated revenues from contracts with customers4,512
 2,263
 2,379
 3,673
 1,697
 993
 985
              
Other revenues             
Revenues from alternative revenue programs(27) 2
 (23) 7
 6
 5
 (4)
Other rate-regulated electric revenues(e)
23
 10
 10
 8
 5
 3
 —
Other rate-regulated natural gas revenues(e)
—
 —
 3
 —
 —
 —
 —
Total other revenues(4) 12
 (10) 15
 11
 8
 (4)
Total rate-regulated revenues for reportable segments$4,508
 $2,275
 $2,369
 $3,688
 $1,708
 $1,001
 $981

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

 Nine Months Ended September 30, 2017
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$2,071
 $1,147
 $1,038
 $1,740
 $751
 $505
 $484
Small commercial & industrial1,035
 303
 193
 373
 105
 139
 129
Large commercial & industrial346
 168
 329
 814
 593
 78
 143
Public authorities & electric railroads33
 23
 23
 45
 24
 11
 10
Other(a)
671
 151
 222
 398
 148
 121
 140
Total rate-regulated electric revenues(b)
4,156
 1,792
 1,805
 3,370
 1,621
 854
 906
Rate-regulated natural gas revenues             
Residential—
 225
 289
 57
 —
 57
 —
Small commercial & industrial—
 90
 51
 25
 —
 25
 —
Large commercial & industrial—
 —
 82
 5
 —
 5
 —
Transportation—
 16
 —
 11
 —
 11
 —
Other(c)
—
 8
 20
 7
 —
 7
 —
Total rate-regulated natural gas revenues(d)
—
 339
 442
 105
 —
 105
 —
Total rate-regulated revenues from contracts with customers4,156
 2,131
 2,247
 3,475
 1,621
 959
 906
              
Other revenues             
Revenues from alternative revenue programs48
 —
 102
 41
 23
 9
 9
Other rate-regulated electric revenues(e)
23
 10
 11
 8
 5
 3
 —
Other rate-regulated natural gas revenues(e)
—
 —
 3
 —
 —
 —
 —
Other revenues(f)
—
 —
 —
 33
 —
 —
 —
Total other revenues71
 10
 116
 82
 28
 12
 9
Total rate-regulated revenues for reportable segments$4,227
 $2,141
 $2,363
 $3,557
 $1,649
 $971
 $915
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $23 million, $5 million, $5 million, $11 million, $5 million, $6 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the nine months ended September 30, 2018 and $12 million, $4 million, $5 million, $2 million, $4 million, $6 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the nine months ended September 30, 2017.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of less than $1 million and $13 million at PECO and BGE, respectively, for the nine months ended September 30, 2018 and less than $1 million and $7 million at PECO and BGE, respectively, for the nine months ended September 30, 2017.
(e)Includes late payment charge revenues.
(f)Includes operating revenues from affiliates of $33 million at PHI for the nine months ended September 30, 2017.

Table of Contents

Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations
(Dollars in millions except per share data, unless otherwise noted)
Exelon
Executive Overview
Exelon, a utility services holding company, operates through the following principal subsidiaries:
Generation, whose integrated business consists of the estimated clean- up costs wasgeneration, 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 transferred to Generationsells renewable energy and is includedother 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 distribution services in the table above as a liabilityPennsylvania counties surrounding the City of Generation. The responsibility to indemnify Calpine is shared by PHIPhiladelphia.
BGE, whose business consists of the purchase and Generation. The ultimate resolutionregulated retail sale of this matter is currently not expected to have a material financial impact on PHIelectricity and Generation.natural gas and the provision of electricity distribution and transmission and gas distribution services in central Maryland, including the City of Baltimore.
Rock Creek Mineral Oil Release.Pepco, In late August 2015, a Pepco undergroundwhose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission line in the District of Columbia sufferedand 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 breach,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 19 — 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 corporate governance support services including corporate strategy and development, legal, human resources, information technology, finance, real estate, security, corporate communications and

Table of Contents

supply at cost. The costs of these services are directly charged or allocated to the applicable operating segments. The services are provided pursuant to service agreements. Additionally, the results of Exelon’s corporate operations include interest costs income from various investment and financing activities.
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 PHISCO and the participating operating subsidiaries.
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.

Table of Contents

Financial Results of Operations
GAAP Results of Operations
The following tables set forth Exelon's GAAP consolidated results of operations for the three and nine months ended September 30, 2018 compared to the same period in 2017. All amounts presented below are before the impact of income taxes, except as noted.
 Three Months Ended September 30, Favorable
(Unfavorable)
Variance
 2018 2017 
 Generation ComEd PECO BGE PHI Other Exelon Exelon 
Operating revenues$5,278
 $1,598
 $757
 $731
 $1,361
 $(322) $9,403
 $8,768
 $635
Purchased power and fuel expense2,980
 619
 263
 272
 509
 (311) 4,332
 3,542
 (790)
Revenue net of purchased power and fuel expense(a)
2,298
 979
 494
 459
 852
 (11) 5,071
 5,226
 (155)
Other operating expenses                 
Operating and maintenance1,370
 337
 219
 182
 292
 (54) 2,346
 2,275
 (71)
Depreciation and amortization468
 237
 75
 110
 192
 23
 1,105
 1,002
 (103)
Taxes other than income143
 82
 46
 64
 123
 11
 469
 456
 (13)
Total other operating expenses1,981
 656
 340
 356
 607
 (20) 3,920
 3,733
 (187)
(Loss) gain on sales of assets and businesses(6) —
 —
 —
 —
 1
 (5) (1) (4)
Bargain purchase gain—
 —
 —
 —
 —
 —
 —
 7
 (7)
Operating income311
 323
 154
 103
 245
 10
 1,146
 1,499
 (353)
Other income and (deductions)                 
Interest expense, net(101) (85) (32) (27) (65) (83) (393) (386) (7)
Other, net179
 7
 2
 5
 11
 (10) 194
 210
 (16)
Total other income and (deductions)78
 (78) (30) (22) (54) (93) (199) (176) (23)
Income (loss) before income taxes389
 245
 124
 81
 191
 (83) 947
 1,323
 (376)
Income taxes78
 52
 (2) 18
 4
 (13) 137
 451
 314
Equity in (losses) earnings of unconsolidated affiliates(11) —
 —
 —
 —
 1
 (10) (7) (3)
Net income (loss)300
 193
 126
 63
 187
 (69) 800
 865
 (65)
Net income attributable to noncontrolling interests66
 —
 —
 —
 —
 1
 67
 42
 (25)
Net income (loss) attributable to common shareholders$234
 $193
 $126
 $63
 $187
 $(70) $733
 $823
 $(90)

Table of Contents

 Nine Months Ended September 30, 
Favorable
(Unfavorable)
Variance
 2018 2017 
 Generation ComEd PECO BGE PHI Other Exelon Exelon 
Operating revenues$15,368
 $4,508
 $2,275
 $2,369
 $3,688
 $(1,038) $27,170
 $25,180
 $1,990
Purchased power and fuel expense8,552
 1,702
 818
 881
 1,410
 (989) 12,374
 10,527
 (1,847)
Revenue net of purchased power and fuel expense(a)
6,816

2,806

1,457

1,488

2,278
 (49)
14,796

14,653
 143
Other operating expenses        

        
Operating and maintenance4,126
 974
 686
 578
 857
 (185) 7,036
 7,658
 622
Depreciation and amortization1,383
 696
 224
 358
 555
 68
 3,284
 2,814
 (470)
Taxes other than income414
 238
 125
 188
 343
 34
 1,342
 1,313
 (29)
Total other operating expenses5,923

1,908

1,035

1,124

1,755
 (83)
11,662

11,785
 123
Gain on sales of assets and businesses48
 5
 1
 1
 —
 —
 55
 4
 51
Bargain purchase gain—
 —
 —
 —
 —
 —
 —
 233
 (233)
Operating income941

903

423

365

523
 34

3,189

3,105
 84
Other income and (deductions)                 
Interest expense, net(305) (261) (96) (78) (193) (205) (1,138) (1,194) 56
Other, net164
 21
 4
 14
 33
 (24) 212
 643
 (431)
Total other income and (deductions)(141)
(240)
(92)
(64)
(160) (229)
(926)
(551) (375)
Income (loss) before income taxes800
 663
 331
 301
 363
 (195) 2,263
 2,554
 (291)
Income taxes110
 140
 (5) 59
 28
 (70) 262
 601
 339
Equity in (losses) earnings of unconsolidated affiliates(23) —
 —
 —
 1
 —
 (22) (25) 3
Net income (loss)667

523

336

242

336

(125)
1,979

1,928
 51
Net income attributable to noncontrolling interests120
 —
 —
 —
 —
 1
 121
 21
 (100)
Net income (loss) attributable to common shareholders$547

$523

$336

$242

$336
 $(126)
$1,858

$1,907
 $(49)
_________
(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 their 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.
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017.Exelon’s Net income attributable to common shareholders was $733 million for the three months ended September 30, 2018 as compared to $823 million for the three months ended September 30, 2017, and diluted earnings per average common share were $0.76 for the three months ended September 30, 2018 as compared to $0.85for the three months ended September 30, 2017.

Table of Contents

Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $155 million for the three months ended September 30, 2018 compared to the same period in 2017 primarily due to the following factors:
Decrease of $121 million at Generation primarily due to the absence of EGTP revenues net of purchased power and fuel expense resulting from its deconsolidation in the fourth quarter of 2017, lower realized energy prices, lower energy efficiency revenues and decreased revenues related to the sale of Generation's electrical contracting business in 2018 and increased nuclear outage days, partially offset by the impact of Illinois ZES and increased capacity prices;
Decrease of $113 million across all Utility Registrants, primarily reflecting lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates, partially offset by regulatory rate increases at ComEd, Pepco, DPL and ACE; and
Increase of $58 million at PECO, DPL and ACE primarily due to favorable weather conditions and volumes within their respective service territories.
Operating and maintenance expense increased by $71 million for the three months ended September 30, 2018 as compared to the same period in 2017 primarily due to the following factors:
Increase of $84 million at Generation due to a charge associated with a remeasurement of the Oyster Creek ARO;
Increase of $40 million at Generation due to higher nuclear refueling outage costs;
Increase of $22 million at Pepco due to a charge associated with a remeasurement of the Buzzard Point ARO; and
Decrease of $50 million at Generation in labor, contracting and materials expense due to decreased spending related to energy efficiency projects and decreased costs related to the sale of Generation's electrical contracting business in 2018.
Depreciation and amortization expense increased by $103 million for the three months ended September 30, 2018 as compared to the same period in 2017 primarily due to ongoing capital expenditures across all operating companies, accelerated depreciation and amortization due to Generation's decision to early retire the Oyster Creek and TMI nuclear facilities, increased amortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues), partially offset by certain regulatory assets that became fully amortized as of December 31, 2017 for BGE.
Other, net decreased by $16 million primarily due to lower net unrealized and realized gains on NDT funds at Generation for the three months ended September 30, 2018 compared to the same period in 2017.
Exelon’s effective income tax rates for the three months ended September 30, 2018 and 2017 were 14.5% and 34.1%, respectively. The decrease in the effective income tax rate for the three months ended September 30, 2018 compared to the same period in 2017 is primarily related to tax savings due to the lower federal income tax rate as a result of the TCJA at all Registrants, which is predominantly offset in Operating revenues at the Utility Registrants for the anticipated pass back of the tax savings through customer rates. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on TCJA's impact on regulatory proceedings.

Table of Contents

Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.Exelon’s Net income attributable to common shareholders was $1,858 million for the nine months ended September 30, 2018 compared to $1,907 million for the nine months ended September 30, 2017, and diluted earnings per average common share were $1.92 for the nine months ended September 30, 2018 compared to $2.02for the nine months ended September 30, 2017.
Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $143 million for the nine months ended September 30, 2018 as compared to the same period in 2017. The year-over-year increase in Revenue net of purchased power and fuel expense was primarily due to the following factors:
Increase of $202 million at Generation primarily due to impact of the New York CES and Illinois ZES (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017), increased capacity prices, the acquisition of the FitzPatrick nuclear facility and decreased nuclear outage days, the addition of two combined-cycle gas turbines in Texas and the impacts of Generation's natural gas portfolio, partially offset by lower realized energy prices, the absence of EGTP revenues net of purchased power and fuel expense resulting from its deconsolidation in the fourth quarter of 2017, lower energy efficiency revenues and decreased revenues related to the sale of Generation's electrical contracting business in 2018;
Increase of $57 million at Generation due to lower mark-to-market losses;
Increase of $132 million at PECO, DPL and ACE primarily due to favorable weather conditions and volumes within their respective service territories;
Increase of $33 million due to higher mutual assistance revenues across all Utility Registrants, primarily at ComEd;
Decrease of $95 million at ComEd primarily due to lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to FEJA; and
Decrease of $274 million in electric and gas revenues across all Utility Registrants, primarily reflecting lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates, partially offset by higher utility revenues due to regulatory rate increases at ComEd, BGE, Pepco, DPL and ACE.
Operating and maintenance expense decreased by $622 million for the nine months ended September 30, 2018 compared to the same period in 2017 primarily due to the following factors:
Decrease of $411 million at Generation due to long-lived asset impairments primarily related to the EGTP assets held for sale in 2017;
Decrease of $163 million at Generation in labor, contracting and materials expense due to decreased spending related to energy efficiency projects and decreased costs related to the sale of Generation's electrical contracting business in 2018.
Decrease of $95 million at ComEd primarily due to the change to defer and recover over time energy efficiency costs pursuant to FEJA;
Decrease of $66 million at Generation due to lower merger-related costs;
Decrease of $56 million at Generation due to lower nuclear refueling outage costs;
Decrease of $32 million due to a supplemental NEIL insurance distribution at Generation;

Table of Contents

Increase of $47 million due to higher one-time charges related to Generation's decision to early retire the Oyster Creek nuclear facility in 2018, including a remeasurement to the ARO, compared to one-time charges related to Generation’s decision to early retire the TMI nuclear facility in 2017;
Increase of $33 million due to higher mutual assistance expenses across all Utility Registrants, primarily at ComEd;
Increase of $97 million at PECO and BGE due to increased storm costs; and
Increase of $22 million at Pepco due to a charge associated with a remeasurement of the Buzzard Point ARO.
Depreciation and amortization expense increased by $470 million for the nine months ended September 30, 2018 compared to the same period in 2017 primarily due to increased depreciation expense as a result of ongoing capital expenditures across all operating companies, accelerated depreciation and amortization due to Generation's decision to early retire the Oyster Creek and TMI nuclear facilities, increased amortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues), partially offset by certain regulatory assets that became fully amortized as of December 31, 2017 for BGE.
Taxes other than income increased due to increased gross receipts tax accruals at PECO and Pepco for the nine months ended September 30, 2018 compared to the same period in 2017.
Gain on sales of assets and businesses increased by $51 million for the nine months ended September 30, 2018 compared to the same period in 2017 primarily due to Generation's sale of its electrical contracting business.
Bargain purchase gain decreased by $233 million due to the gain associated with the FitzPatrick acquisition in the first quarter of 2017.
Interest expense, net decreased by $56 million due to retirement of long-term debt.
Other, net decreased by $431 million primarily due to lower net unrealized and realized gains on NDT funds at Generation for the nine months ended September 30, 2018 compared to the same period in 2017.
Exelon’s effective income tax rates for the nine months ended September 30, 2018 and 2017 were 11.6% and 23.5%, respectively. The decrease in the effective income tax rate for the nine months ended September 30, 2018 compared to the same period in 2017 is primarily related to tax savings due to the lower federal income tax rate as a result of the TCJA at all Registrants, which is offset in Operating revenues at the Utility Registrants for the anticipated pass back of the tax savings through customer rates. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on TCJA's impact on regulatory proceedings.
For additional information regarding the financial results for the three and nine months ended September 30, 2018, including explanation of the non-GAAP measure Revenue net of purchased power and fuel expense, see the discussions of Results of Operations by Registrant below.
Adjusted (non-GAAP) Operating Earnings
Exelon’s adjusted (non-GAAP) operating earnings for the three months ended September 30, 2018 were $856 million, or $0.88 per diluted share, compared with adjusted (non-GAAP) operating earnings

Table of Contents

of $820 million, or $0.85 per diluted share for the same period in 2017. Exelon’s adjusted (non-GAAP) operating earnings for the nine months ended September 30, 2018 were $2,467 million, or $2.55 per diluted share, compared with adjusted (non-GAAP) operating earnings of $1,943 million, or $2.06 per diluted share for the same period in 2017. 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 period-over-period 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.

Table of Contents

The following tables provide a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2018 compared to the same period in 2017.
 Three Months Ended September 30,
 2018 2017
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$733
 $0.76
 $823
 $0.85
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $20 and $29, respectively)
(55) (0.06) (45) (0.05)
Unrealized Gains Related to NDT Fund Investments(b) (net of taxes of $4 and $51, respectively)
(53) (0.06) (67) (0.07)
Amortization of Commodity Contract Intangibles(c) (net of taxes of $0 and $8, respectively)
—
 —
 12
 0.01
Merger and Integration Costs(d) (net of taxes of $0 and $1, respectively)
—
 —
 (1) —
Long-Lived Asset Impairments(f) (net of taxes of $2 and $16, respectively)
6
 0.01
 24
 0.03
Plant Retirements and Divestitures(g) (net of taxes of $70 and $47, respectively)
202
 0.21
 71
 0.08
Cost Management Program(h) (net of taxes of $4 and $8, respectively)
13
 0.01
 13
 0.01
Bargain Purchase Gain(i) (net of taxes of $0 and $0, respectively)
—
 —
 (7) (0.01)
Asset Retirement Obligation(n) (net of taxes of $6 and $1, respectively)
16
 0.02
 (2) —
Change in Environmental Liabilities (net of taxes of $3 and $0, respectively)(9) (0.01) —
 —
Reassessment of Deferred Income Taxes(k) (entire amount represents tax expense)
(18) (0.02) (21) (0.02)
Noncontrolling Interests(m) (net of taxes of $4 and $4, respectively)
21
 0.02
 20
 0.02
Adjusted (non-GAAP) Operating Earnings$856
 $0.88
 $820
 $0.85

Table of Contents

 Nine Months Ended September 30,
 2018 2017
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$1,858
 $1.92
 $1,907
 $2.02
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $26 and $62, respectively)
74
 0.08
 97
 0.10
Unrealized Losses (Gains) Related to NDT Fund Investments(b) (net of taxes of $118 and $181, respectively)
94
 0.10
 (211) (0.22)
Amortization of Commodity Contract Intangibles(c) (net of taxes of $0 and $17, respectively)
—
 —
 27
 0.03
Merger and Integration Costs(d) (net of taxes of $1 and $24, respectively)
5
 —
 39
 0.04
Merger Commitments(e) (net of taxes of $0 and $137, respectively)
—
 —
 (137) (0.15)
Long-Lived Asset Impairments(f) (net of taxes of $13 and $188, respectively)
36
 0.04
 293
 0.31
Plant Retirements and Divestitures(g) (net of taxes of $148 and $89, respectively)
422
 0.43
 137
 0.15
Cost Management Program(h) (net of taxes of $10 and $15, respectively)
29
 0.03
 24
 0.03
Bargain Purchase Gain(i) (net of taxes of $0 and $0, respectively)
—
 —
 (233) (0.25)
Asset Retirement Obligation(n) (net of taxes of $6 and $1, respectively)
16
 0.02
 (2) —
Change in Environmental Liabilities (net of taxes of $1 and $0, respectively)(4) —
 —
 —
Like-Kind Exchange Tax Position(j) (net of taxes of $0 and $66, respectively)
—
 —
 (26) (0.03)
Reassessment of Deferred Income Taxes(k) (entire amount represents tax expense)
(27) (0.03) (42) (0.04)
Tax Settlements(l) (net of taxes of $0 and $1, respectively)
—
 —
 (5) (0.01)
Noncontrolling Interests(m) (net of taxes of $9 and $16, respectively)
(36) (0.04) 75
 0.08
Adjusted (non-GAAP) Operating Earnings$2,467
 $2.55
 $1,943
 $2.06
_________
Note:
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2018 and 2017 ranged from 26.0 percent to 29.0 percent and 39.0 percent to 41.0 percent, respectively. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 7.7 percent and 43.2 percent for the three months ended September 30, 2018 and 2017, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 55.5 percent and 46.2 percent for the nine months ended September 30, 2018 and 2017, respectively.
(a)Primarily reflects the impact of net gains and losses on Generation’s economic hedging activities.
(b)Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.

Table of Contents

(c)Reflects the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.
(d)
Primarily reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2017, reflects costs related to the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs. In 2018, reflects costs related to the PHI acquisition.
(e)Primarily reflects a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.
(f)Primarily reflects charges to earnings related to the impairment of the EGTP assets held for sale in 2017, and in 2018 the impairment of certain wind projects at Generation.
(g)Primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the Three Mile Island nuclear facility in 2017. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO and accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the Three Mile Island nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business.
(h)Primarily represents severance and reorganization costs related to a cost management program.
(i)Represents the excess fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.
(j)Reflects adjustments to income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.
(k)Reflects the changes in the Illinois and District of Columbia statutory tax rate and changes in forecasted apportionment in 2017. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the Tax Cuts and Jobs Act (TCJA) and changes in forecasted apportionment.
(l)Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI’s unregulated business interests.
(m)Reflects elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.
(n)Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units in 2017. In 2018, reflects an increase at Pepco related primarily to asbestos identified at its Buzzard Point property.
Significant 2018 Transactions and Developments
Regulatory Implications of the Tax Cuts and Jobs Act (TCJA)
The Utility Registrants have made filings with their respective State regulators to begin passing back to customers the ongoing annual tax savings resulting from the TCJA. The amounts being proposed to be passed back to customers reflect the annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. The Utility Registrants have identified over $675 million in ongoing annual savings to be returned to customers related to TCJA from their distribution utility operations. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Early Plant Retirements
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in 2018. On September 17, 2018, Oyster Creek permanently ceased generation operations. Because of the decision to early retire Oyster Creek in 2018, Exelon and Generation recognized certain one-time charges in the first quarter of 2018 related to a materials and supplies inventory reserve adjustment, employee-related costs and construction work-in-progress impairments, among other items.
On July 31, 2018, Generation entered into an agreement with Holtec International and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the sale and decommissioning of Oyster Creek. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
On May 30, 2017, Generation announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The plant is currently committed to operate through May 2019.
As a result of the early nuclear plant retirement decisions at Oyster Creek and TMI, Exelon and Generation will also recognize annual incremental non-cash charges to earnings stemming from

Table of Contents

shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions were also recorded. The following table summarizes the actual incremental non-cash expense item incurred in 2018 and the estimated amount of incremental non-cash expense items expected to be incurred in 2018 and 2019 due to the early retirement decisions.
 Actual 
Projected(a)
Income statement expense (pre-tax)Nine Months Ended September 30, 2018 2018 2019
Depreciation and amortization(b)
     
         Accelerated depreciation(c)
$441
 $550
 $330
         Accelerated nuclear fuel amortization52
 55
 5
Operating and maintenance(d)
32
 35
 5
Total$525
 $640
 $340
_________
(a)Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.
(b)Reflects incremental accelerated depreciation and amortization for TMI and Oyster Creek for the nine months ended September 30, 2018. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018.
(c)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(d)Primarily includes materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments.
In 2017, PSEG also made public financial challenges facing its New Jersey nuclear plants including Salem, of which Generation owns a 42.59% ownership interest. Although Salem is committed to operate through May 2021, the plant faces continued economic challenges and PSEG, as the operator of the plant, is exploring all options.
On May 23, 2018, the Governor of New Jersey signed new legislation, which became effective immediately, that will establish a ZEC program providing compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the new legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. The NJBPU has 180 days from the effective date to establish procedures for implementation of the ZEC program and 330 days from the effective date to determine which nuclear power plants are selected to receive ZECs under the program. Assuming the successful implementation of the New Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk of earlier retirement for Salem. See Note 6 — Regulatory Matters and Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information on the new legislation and the New Jersey ZEC program.
On March 29, 2018, based on ISO-NE capacity auction results for the 2021 - 2022 planning year in which Mystic Unit 9 did not clear, Generation announced it had formally notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets on June 1, 2022 absent any interim and long-term solutions for reliability and regional fuel security. The ISO-NE announced that it would take a three-step approach to fuel security. First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel security for the 2022 - 2024 planning years.  Second, ISO-NE planned to file tariff revisions to allow it to retain other resources for fuel security in the capacity market if necessary in the future. Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot

Table of Contents

recover future operating costs including the cost of procuring fuel. As a result of these developments, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group during the first quarter of 2018 and no impairment charge was required.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024.
On July 2, 2018, FERC issued an order denying ISO-NE's May 1, 2018, waiver request on procedural grounds but accepting ISO-NE's conclusions that retirement of Mystic Units 8 and 9 could cause a violation of mandatory reliability standards as soon as 2022. Accordingly, FERC ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address demonstrated fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. FERC also extended the deadline by which Generation must make a retirement decision for Mystic Units 8 and 9 to January 4, 2019. On August 31, 2018, ISO-NE filed a compliance filing in response to FERC's July 2, 2018 order proposing short-term tariff changes to permit it to retain a resource for fuel security reliability reasons. A number of parties, including Generation, have submitted comments on the proposal, which is pending before FERC.
On July 13, 2018, FERC issued an order accepting the cost-of-service agreement for filing, making findings on certain issues and establishing hearing procedures on an expedited schedule. Further developments such as the failure of ISO-NE to adopt interim and long-term solutions for reliability and fuel security could potentially result in future impairments of the New England asset group, which could be material. See Note 7 — Impairment of Long-Lived Assets and Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Illinois ZEC Procurement
Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue. Winning bidders are entitled to compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. During the three months ended September 30, 2018, Generation recognized revenue of $61 million. During the nine months ended September 30, 2018, Generation recognized revenue of $315 million, of which $150 million related to ZECs generated from June 1, 2017 through December 31, 2017.
Westinghouse Electric Company LLC Bankruptcy
On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. On January 4, 2018, Westinghouse announced its agreement to be purchased by an affiliate of Brookfield Business Partners, LLC (Brookfield) for approximately $4.6 billion. On March 28, 2018, the Bankruptcy Court entered an Order confirming the Debtor's Second Amended Joint Plan of Reorganization which provides for the transaction with Brookfield. The transaction closed on August 1, 2018. Exelon had contracts with Westinghouse primarily related to Generation's purchase of nuclear fuel, as well as a variety of services and equipment purchases associated with the operation and maintenance of nuclear generating stations. In conjunction with the confirmation hearing, Exelon had filed a reservation of rights regarding reorganizing Westinghouse's assumption of all Exelon contracts. Exelon reached an agreement with Brookfield, and all Exelon contracts were assumed by Brookfield on the closing date.

Table of Contents

Utility Rates and Base Rate Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2018. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
Registrant Jurisdiction 
Approved Revenue Requirement Increase (Decrease)
(in millions)
 Approved Return on Equity Completion Date Rate Effective Date
Pepco District of Columbia (Electric) $(24) 9.525% August 9, 2018 August 13, 2018
Pepco Maryland (Electric) $(15) 9.5% May 31, 2018 June 1, 2018
DPL Delaware (Electric) $(7) 9.7% August 21, 2018 March 17, 2018
DPL Maryland (Electric) $13
 9.5% February 9, 2018 September 5, 2018
Pending Distribution Base Rate Case Proceedings
Registrant Jurisdiction 
Requested or Settlement Revenue Requirement Increase (Decrease)
(in millions)
 Requested or Settlement Return on Equity Filing or Settlement Date Expected Completion Timing
ComEd Illinois (Electric) $(23) 8.69% April 16, 2018 Fourth quarter 2018
PECO Pennsylvania (Electric) $25
 
N/A(a)

 August 28, 2018 Fourth quarter 2018
BGE Maryland (Natural Gas) $61
 10.50% June 8, 2018 (Updated on August 24, 2018 and October 12, 2018) First quarter 2019
DPL Delaware (Natural Gas) $(4) 9.70% September 7, 2018 (Updated on October 2, 2018) Fourth quarter 2018
ACE New Jersey (Electric) $109
 10.10% August 21, 2018 Third quarter 2019
__________
(a)No overall ROE was specified in the partial settlement agreement.
See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these base rate case proceedings.

Table of Contents

Transmission Formula Rate
The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2018 annual electric transmission formula rate updates.
 2018
Annual Transmission Updates(a)(b)
ComEd BGE Pepco DPL ACE
Initial revenue requirement (decrease) increase$(44) $10
 $6
 $14
 $4
Annual reconciliation increase (decrease)18
 4
 2
 13
 (4)
Dedicated facilities increase(c)
—
 12
 —
 —
 —
Total revenue requirement (decrease) increase$(26) $26
 $8
 $27
 $—
          
Allowed return on rate base(d)
8.32% 7.61% 7.82% 7.29% 8.02%
Allowed ROE(e)
11.50% 10.50% 10.50% 10.50% 10.50%
_________
(a)All rates are effective June 2018, subject to review by the FERC and other parties, which is due by fourth quarter 2018.
(b)The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA.  See further discussion above. 
(c)BGE's transmission revenues include a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to a specifically designated load by BGE.
(d)Represents the weighted average debt and equity return on transmission rate bases.
(e)As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization.
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the final outcome of this proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a revenue decrease of $6 million. The revenue decrease of $6 million included an approximately $20 million reduction as a result of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.


Table of Contents

Winter Storm-Related Costs
During March 2018 there were powerful nor'easter storms that brought a mix of heavy snow, ice and high sustained winds and gusts to the region that interrupted electric service delivery to customers in PECO's, BGE's, Pepco's, DPL's and ACE's service territories. Restoration efforts included significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies, which resulted in incremental operating and maintenance expense and incremental capital expenditures in the first quarter of 2018 for PECO, BGE, PHI, Pepco, DPL and ACE. In addition, PHI, Pepco, DPL and ACE recorded regulatory assets for amounts that are probable of recovery through customer rates. The impacts recorded by the Registrants for the nine months ended September 30, 2018 are presented below:
   (in millions)
 Customer Outages Incremental Operating & Maintenance Incremental Capital Expenditures
Exelon1,727,000
 $88
(b) 
$89
PECO750,000
 53
 35
BGE425,000
 31
 15
PHI(a)
552,000
 4
(b) 
39
Pepco182,000
 2
(b) 
4
DPL138,000
 2
(b) 
4
ACE232,000
 —
(b) 
31
________
(a)PHI reflects the consolidated customer outages, incremental operating & maintenance and incremental capital expenditures of Pepco, DPL and ACE.
(b)Excludes amounts that were deferred and recognized as regulatory assets at Exelon, PHI, Pepco, DPL and ACE of $28 million, $28 million, $7 million, $1 million and $20 million, respectively.
Exelon’s Strategy and Outlook for 2018 and Beyond
Exelon’s value proposition and competitive advantage come from its scope and its core strengths of operational excellence and financial discipline. Exelon leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition:
The Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and in long-term, contracted assets and to reduce debt.
Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart meter

Table of Contents

technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon's Board of Directors has approved a dividend policy providing a raise of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS of the Exelon 2017 Form 10-K for additional information regarding market and financial factors.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy.  In August 2015, Exelon announced a cost management program focused on cost savings of approximately $400 million at BSC and Generation, which was fully realized in 2018.  Approximately 75% of the savings were related to Generation, with the remaining amount related to the Utility Registrants. In November 2017, Exelon announced a commitment for an additional $250 million of cost savings, primarily at Generation, to be achieved by 2020. In November 2018, Exelon announced the elimination of an approximately additional $200 million of annual ongoing costs, through initiatives primarily at Generation and BSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The PHI merger 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 $28 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 $11 billion by the end of 2022. 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.

Table of Contents

See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements Exelon 2017 Form 10-K 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 its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.
Liquidity Considerations
Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
Exelon Corporate, 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 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion.
For additional information regarding the Registrants' liquidity for the nine months ended September 30, 2018, see Liquidity and Capital Resources discussion below.
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 debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.

Table of Contents

Other Key Business Drivers and Management Strategies
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
FERC Inquiry on Resiliency
On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On January 8, 2018, FERC issued an order terminating the rulemaking docket that it initiated to address the proposed rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, FERC initiated a new proceeding to consider resiliency challenges to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. FERC directed each RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Thereafter, interested parties submitted reply comments on May 9, 2018, and a few parties submitted further replies. Exelon has been and will continue to be an active participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs
PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a government-provided financial support program - resulting in a higher offer that may not clear the releasecapacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new gas-fired resources.
On January 9, 2017, EPSA filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. A similar complaint also against PJM was filed at FERC on May 31, 2018. These complaints generally allege that the relevant MOPR should be expanded to also apply to existing resources including those receiving ZEC compensation under the New York CES and Illinois ZES programs. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS programs that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation (Quad Cities, Ginna, Fitzpatrick and Nine Mile Point), an expanded MOPR could require exclusion of non-toxic mineral oil surroundingZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in future capacity auctions and thus no longer receiving capacity revenues during the transmission line intorespective ZEC programs. Any mitigation of these generating resources could have a material effect on Exelon’s

Table of Contents

and Generation’s future cash flows and results of operations. The same risk would also exist for the surrounding soil,Salem facility if Salem is selected as an eligible facility under the NJ ZEC program.
Separately, PJM submitted two proposed alternative capacity market reforms in April 2018 for FERC’s consideration. PJM argued that either alternative will resolve any conflict between state policy support for certain resources and the need to ensure reasonable prices for non-supported resources. The first alternative was to implement a twice-run capacity clearing mechanism (known as the repricing proposal) and, if not acceptable to FERC, a second alternative that would expand the existing MOPR to both new and existing generating resources, subject to certain exemptions (known as MOPREx).
In June 2018, FERC issued an order rejecting both of PJM’s proposed alternatives, finding both to be unjust and unreasonable. In the same order, FERC also addressed one of the MOPR complaints involving PJM and concluded based on that complaint and PJM’s filing that PJM’s existing tariff allows resources receiving out-of-market support to affect capacity prices in a manner that will cause unjust and unreasonable and unduly discriminatory rates in PJM regardless of the intent motivating the support. FERC suggested that modifying two elements of PJM’s existing tariff could produce a just and reasonable replacement and asked for initial comments on its proposal by August 28, 2018, later extended to October 2, 2018. First, FERC found that an expansion of the current MOPR mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or REC compensation, could protect the capacity markets from unwanted price suppression. Second, FERC preliminarily found that a modified version of PJM’s existing Fixed Resource Requirement (FRR) option could enable state subsidized resources and a smallcorresponding amount reached Rock Creekof load to be removed from the capacity market, thereby alleviating their price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through mechanisms other than through PJM’s existing market mechanism. FERC established March 21, 2016 as the refund effective date and also allowed PJM to delay its next capacity auction from May 2019 to August 2019 to allow parties time to develop and file proposals in the FERC proceeding, FERC time to determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates, environmental organizations and other nuclear generators, submitted shared principles supporting a storm drain. Pepco notified regulatory authorities,workable new FRR mechanism (as suggested by FERC) and Pepcodetailing how such a mechanism should be implemented. Exelon also submitted individual comments covering matters not addressed in the shared principles. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. It is too early to predict the final outcome of each of these proceedings or their potential financial impact, if any, on Exelon or Generation.
Section 232 Uranium Petition
On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce (DOC) seeking relief under Section 232 of the Trade Expansion Act of 1962 (as amended) from imports of uranium products, alleging that these imports threaten national security (the Petition). The Trade Expansion Act of 1962 (the Act) was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and its spill response contractors placed booms in Rock Creek, blockedeconomic security of the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission lineU.S. and the Rock Creek shoreline.ability of the country to sustain an independent nuclear fuel cycle.
On July 18, 2018, the Secretary announced that the DOC has initiated an investigation in response to the petition. The Secretary has 270 days to prepare and submit a report to President Trump, who then has 90 days to act on the Secretary's recommendations. Exelon and Generation cannot currently predict the outcome of this investigation. The relief sought by the petitioners would require U.S. nuclear reactors

Table of Contents

to purchase at least 25% of their uranium needs from domestic mines over the next 10 years, although the DOC will make an independent determination regarding an appropriate remedy should it find that imports impair national security. It is reasonably possible that if this petition is successful the resulting increase in nuclear fuel costs in future periods could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.
Potential DOE Order Pursuant to Defense Production Act and Federal Power Act
The DOE is considering an Order directing ISOs, for 24 months, to purchase electric energy or generation capacity from a designated list of coal and nuclear generation facilities. Based on a draft memorandum, the Order would be pursuant to DOE's authorities under the Defense Production Act and Federal Power Act, and would forestall any further actions towards retiring, decommissioning, or deactivating coal and nuclear facilities during the term of the Order. The Order would emphasize the importance of grid resiliency, in addition to grid reliability, noting that fuel security and diversity are critical components of resiliency. The DOE recognizes that the underlying economic and regulatory issues are complex and will take time resolve. The Order's 24-month duration would enable DOE to conduct additional analyses to gain a detailed understanding of location-specific vulnerabilities in U.S. energy delivery systems, while preserving certain generation facilities. Exelon has been and will continue to be an active participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
Energy Demand
Modest economic growth partially offset by energy efficiency initiatives is resulting in relatively flat load growth in electricity for the Utility Registrants. ComEd, PECO, BGE, Pepco, estimatesDPL and ACE are projecting load volumes to increase by 0.5%, 1.7%, 0.7%, 0.2%, 1.3% and 4.3% respectively, in 2018 compared to 2017.
Retail Competition
Generation’s retail operations compete for customers in a competitive environment, which affect the margins that approximately 6,100 gallonsGeneration can earn and the volumes that it is able to serve. Forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of mineral oil were releasedmarket 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 remediation efforts recovered approximately 80%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 2018 dividends of $0.345 per share on Exelon's common stock. The first quarter 2018 dividend was paid on March 9, 2018. The dividend increased from the fourth quarter 2017 amount to reflect the Board's decision to raise Exelon's dividend 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
Exelon's board of directors declared second quarter 2018 dividends of $0.345 per share on Exelon's common stock and was paid on June 8, 2018.
Exelon's board of directors declared third quarter 2018 dividends of $0.345 per share on Exelon's common stock and was paid on September 10, 2018.

Table of Contents

Exelon's board of directors declared fourth quarter 2018 dividends of $0.345 per share on Exelon's common stock and is payable on December 10, 2018.
All future quarterly dividends require approval by Exelon's Board of Directors.
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 2018 and 2019. 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 September 30, 2018, the percentage of expected generation hedged is 98%-101%, 82%-85% and 48%-51% for 2018, 2019, and 2020 respectively. The percentage of expected generation hedged is the amount released. Pepco’s remediation effortsof 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 ongoingcalibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.
Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 59% of Generation’s uranium concentrate requirements from 2018 through 2022 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 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.
PHI and Pepco have reached a settlement with a third party who contributed to the loss. Exelon, PHI and Pepco do not believe that the balance of the remediation costs to resolve this matter willcurrent supply agreements. Non-performance by these counterparties could have a material adverse effectimpact on their respective financial condition,Exelon’s and Generation’s results of operations, cash flows and financial positions.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Environmental Legislative and Regulatory Developments
Exelon was actively involved in the Obama Administration’s development and implementation of environmental regulations for the electric industry, in pursuit of its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil fuel plants.

Table of Contents

Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.
In particular, the Administration has targeted certain existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings and withdrew all technical support documents supporting the calculation. Other regulations that are under review include the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the Coal Combustion Residuals rule. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.
Air Quality
Brandywine Fly Ash Disposal Site. 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 February 2013, Pepco receivedApril 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court to take further action consistent with the U.S. Supreme Court’s opinion on this single issue. On April 27, 2017, the D.C. Circuit granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. Notwithstanding the Court’s order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule.
Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a letter fromdetermination whether the MDE requesting that Pepco investigaterule should be remanded to the extent of wasteEPA. On October 10, 2017, EPA issued a proposed rule to repeal the CPP in its entirety, based on a Pepco right-of-wayproposed change in the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that traverses the Brandywine fly ash disposal siteAgency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. The EPA has also issued an advance notice of proposed rulemaking to solicit information on systems of emission reduction that are in Brandywine, Prince George’s County, Maryland, ownedaccord with the Agency’s proposed revised legal interpretation; namely, only by NRG Energy, Inc. (as successorregulating emission reductions that can be implemented at and to GenOn MD Ash Management, LLC) (NRG)individual sources.

Table of Contents

2015 Ozone National Ambient Air Quality Standards (NAAQS). In July 2013, while reserving On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. Concurrent with its rightsreview, the Agency issued several rounds of final ozone designations for the 2015 ozone NAAQS in December 2017 and related defenses underApril 2018. On August 1, 2018, EPA filed a 2000 agreement coveringstatus report to the sale ofCourt that indicated Agency does not intend to revise or repeal the 2015 ozone standard at this site, Pepco indicatedtime. Subsequently the Court ordered the case reactivated.
Primary SO2 National Ambient Air Quality Standards (NAAQS). On June 8, 2018, the EPA proposed to maintain the primary NAAQS for sulfur dioxide (SO2) at the same level and averaging time as was finalized by EPA in its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a2010 SO2 NAAQS update. The schedule for developmentcompleting this review is established by a consent decree, which sets January 28, 2019 as the deadline for signature on a final decision notice.
Climate Change. Exelon supports comprehensive climate change legislation or regulation which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In June 2018, Exelon joined the Climate Leadership Council, which advocates for a revenue neutral carbon tax and dividend program. In the absence of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approvedFederal legislation, the schedule.
Exelon, PHI and PepcoEPA has been reviewing the regulation of GHG emissions under the Clean Air Act. In addition, there 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 arebeen recent developments in the rangeinternational regulation of approximately $3 millionGHG emissions pursuant to $6 million,the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). See ITEM 1. BUSINESS, "Air Quality" of the Exelon 2017 Form 10-K 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.additional information.
Litigation and Regulatory Matters
PHI Merger (Exelon and PHI)
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 Exelon and PHI merger. The Circuit Court judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, CCAN and Public Citizen, Inc. On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed notices of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment that the MDPSC did not err in approving the merger. The OPC and Sierra Club filed petitions seeking further review in the Court of Appeals of Maryland, which is the highest court in Maryland. On June 21, 2017, the Court of Appeals granted discretionary review of the January 27, 2017 decision by the Maryland Court of Special Appeals. The Maryland Court of Appeals will review the OPC argument that the MDPSC did not properly consider the acquisition premium paid to PHI shareholders under Maryland’s merger approval standard and the Sierra Club’s argument that the merger would harm the renewable and distributed generation markets. The two lower courts examining these issues rejected these arguments, which Exelon believes are without merit. All briefs have been filed and oral arguments were presented to the court on October 10, 2017. On August 29, 2018, the Maryland Court of Appeals affirmed the MDPSC's May 2015 Order approving the merger of Exelon and PHI. This concluded the final legal challenge to the merger of Exelon and PHI.
Asbestos Personal Injury Claims (Exelon, Generation, ComEd, PECO and BGE)ComEd)
Exelon, Generation and PECO. 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 isestimated liabilities are recorded on an undiscounted basis and excludesexclude the estimated legal costs associated with handling these matters, which could be material.
At September 30, 20172018 and December 31, 2016,2017, Generation had reservedrecorded estimated liabilities of approximately $80 million and $83$78 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2017,2018, approximately $22$24 million of this amount related to 227241 open claims presented to Generation, while the remaining $58$56 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial

163
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

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 adjustmentadjustments to the reserve isestimated liabilities are 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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars 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 for on a claim by claim basis. Those additional claims are taken into account in projecting estimates of future asbestos-related bodily injury claims.millions, except per share data, unless otherwise noted)
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. Since the Illinois Supreme Court’s ruling in November 2015, Exelon, Generation, and ComEd have not experienced a significant increase in asbestos-related personal injury claims brought by former ComEd employees.
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 effectunfavorable impact on Exelon's, Generation's ComEd's, PECO and BGE's futurePECO's financial conditions, 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 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 September 30, 2017 and December 31, 2016, ComEd did not have any material liabilities recorded for these storm events.
Baltimore City Franchise Taxes (Exelon and 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.

164
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

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 2016 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.
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 of the Superior Court’s summary judgment decision with the Supreme Court of Delaware. Generation has accrued an amount to cover its potential liability.
City of Everett Tax Increment Financing Agreement (Exelon)(Exelon and Generation)
TheOn April 10, 2017, the City of Everett has filed a petition withpetitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 &and 9 on the grounds that the total investment in Mystic Units 8 &and 9 materially deviates from the investment set forth in the TIF Agreement. The EACC has appointedOn October 31, 2017, a three-member panel to conductof the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. Generation has reviewedvigorously contested the City’s claims before the EACC and will continue to do so in the Massachusetts Superior Court proceeding. Generation continues to believe that the City’s claim and believes that it lacks merit. Accordingly, Generation has not recorded an accruala liability for payment resulting from such a revocation, because thenor can Generation estimate a reasonably possible range of loss, if any, cannot beassociated with any such revocation. Further, it is reasonably estimated at this time. Propertypossible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2019, could be material to Generation’s results of operations and cash flows.
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,reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
Income Taxes (Exelon, Generation, ComEd, PECO and BGE)
See Note 12 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

165
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

19.18. 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 three and nine months ended September 30, 20172018 and 2016.2017.
 Three Months Ended September 30, 2017
           Successor      
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on decommissioning trust funds(a)
                 
Regulatory agreement units$159
 $159
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units59
 59
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on decommissioning trust funds                 
Regulatory agreement units44
 44
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units111
 111
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                 
Zion Station decommissioning(4) (4) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(161) (161) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities208
 208
 —
 —
 —

—
 —
 —
 —
Investment income2
 1
 —
 —
 —
 1
 1
 —
 —
Interest income related to uncertain income tax positions4
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity17
 —
 2
 2
 4
 9
 6
 2
 1
Other6
 —
 3
 —
 —
 3
 —
 2
 —
Other, net$237

$209

$5

$2

$4

$13

$7

$4

$1
Nine Months Ended September 30, 2017
          Successor      Three Months Ended September 30, 2018
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                                  
Decommissioning-related activities:                                  
Net realized income on decommissioning trust funds(a)
                                  
Regulatory agreement units$439
 $439
 $—
 $—
 $—
 $—
 $—
 $—
 $—
$214
 $214
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units165
 165
 —
 —
 —
 —
 —
 —
 —
58
 58
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on decommissioning trust funds                 
Net unrealized (losses) gains on decommissioning trust funds                 
Regulatory agreement units253
 253
 —
 —
 —
 —
 —
 —
 —
(66) (66) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units347
 347
 —
 —
 —
 —
 —
 —
 —
72
 72
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                                  
Zion Station decommissioning(5) (5) —
 —
 —
 —
 —
 —
 —
(9) (9) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(558) (558) —
 —
 —
 —
 —
 —
 —
(110) (110) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities641
 641
 —
 —
 —
 —

—
 —
 —
159
 159
 —
 $—
 —

—
 —
 —
 —
Investment income6
 4
 —
 —
 —
 2
 1
 —
 —
9
 5
 —
 —
 —
 2
 1
 1
 —
Interest income related to uncertain income tax positions3
 —
 —
 —
 —
 —
 —
 —
 —
1
 —
 —
 —
 —
 —
 —
 —
 —
Benefit related to uncertain income tax positions(c)
2
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity51
 —
 6
 6
 12
 27
 17
 5
 5
16
 —
 4
 1
 5
 6
 6
 —
 —
Non-service net periodic benefit cost(12) —
 —
 —
 —
 —
 —
 —
 —
Other22
 3
 8
 —
 —
 11
 4
 5
 1
21
 15
 3
 1
 —
 3
 —
 1
 1
Other, net$725

$648

$14

$6

$12
 $40

$22

$10

$6
$194

$179

$7

2

$5

$11

$7

$2

$1

166
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Three Months Ended September 30, 2016
          Successor      Nine Months Ended September 30, 2018
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                                  
Decommissioning-related activities:                                  
Net realized income on decommissioning trust funds(a)
                                  
Regulatory agreement units$57
 $57
 $—
 $—
 $—
 $—
 $—
 $—
 $—
$476
 $476
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units35
 35
 —
 —
 —
 —
 —
 —
 —
257
 257
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on decommissioning trust funds                 
Net unrealized losses on decommissioning trust funds                 
Regulatory agreement units155
 155
 —
 —
 —
 —
 —
 —
 —
(335) (335) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units116
 116
 —
 —
 —
 —
 —
 —
 —
(143) (143) —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                                  
Zion Station decommissioning(5) (5) —
 —
 —
 —
 —
 —
 —
(7) (7) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(168) (168) —
 —
 —
 —
 —
 —
 —
(110) (110) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities190
 190
 —
 —
 —

—

—
 —
 —
138
 138
 —
 —
 —
 —

—
 —
 —
Investment income (expense)2
 1
 —
 (1) —
 —
 —
 —
 —
Investment income19
 12
 —
 —
 —
 3
 1
 1
 —
Interest income related to uncertain income tax positions8
 —
 —
 —
 —
 —
 —
 —
 —
5
 1
 —
 —
 —
 —
 —
 —
 —
Penalty related to uncertain income tax positions(c)
(106) —
 (86) —
 —
 —
 —
 —
 —
AFUDC — Equity19
 —
 5
 2
 5
 7
 5
 1
 1
47
 —
 12
 3
 13
 19
 17
 2
 —
Non-service net periodic benefit cost(33) —
 —
 —
 —
 —
 —
 —
 —
Other7
 (6) 1
 1
 —
 12
 7
 2
 1
36
 13
 9
 1
 1
 11
 5
 4
 2
Other, net$120

$185

$(80)
$2

$5
 $19

$12

$3

$2
$212

$164

$21

$4

$14
 $33

$23

$7

$2
 Three Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on decommissioning trust funds(a)
                 
Regulatory agreement units$159
 $159
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units59
 59
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on decommissioning trust funds                 
Regulatory agreement units44
 44
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units111
 111
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                 
Zion Station decommissioning(4) (4) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(161) (161) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities208
 208
 —
 —
 —

—

—
 —
 —
Investment income2
 1
 —
 —
 —
 1
 1
 —
 —
Interest expense related to uncertain income tax positions4
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity17
 —
 2
 2
 4
 9
 6
 2
 1
Non-service net periodic benefit cost(27) —
 —
 —
 —
 —
 —
 —
 —
Other6
 —
 3
 —
 —
 3
 —
 2
 —
Other, net$210

$209

$5

$2

$4
 $13

$7

$4

$1

167
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

                Successor  Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016  January 1, 2016 to March 23, 2016Nine Months Ended September 30, 2017
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI  PHIExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                                     
Decommissioning-related activities:                                     
Net realized income on decommissioning trust funds(a)
                                     
Regulatory agreement units$181
 $181
 $—
 $—
 $—
 $—
 $—
 $—
 $—
  $—
$439
 $439
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units95
 95
 —
 —
 —
 —
 —
 —
 —
  —
165
 165
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on decommissioning trust funds                                     
Regulatory agreement units286
 286
 —
 —
 —
 —
 —
 —
 —
  —
253
 253
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units216
 216
 —
 —
 —
 —
 —
 —
 —
  —
347
 347
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                                     
Zion Station decommissioning(2) (2) —
 —
 —
 —
 —
 —
 —
  —
(5) (5) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(380) (380) —
 —
 —
 —
 —
 —
 —
  —
(558) (558) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities396
 396
 —
 —
 —

—
 —
 —
 —
  —
641
 641
 —
 —
 —
 —

—
 —
 —
Investment income (expense)14
 6
 —
 (1) 2
 —
 —
 —
 1
  —
Long-term lease income4
 —
 —
 —
 —
 —
 —
 —
 —
  —
Investment income6
 4
 —
 —
 —
 2
 1
 —
 —
Interest income related to uncertain income tax positions13
 —
 —
 —
 —
 1
 —
 1
 —
  —
3
 —
 —
 —
 —
 —
 —
 —
 —
Penalty related to uncertain income tax positions(c)
(106) —
 (86) —
 —
 —
 —
 —
 —
  —
Penalty income related to uncertain income tax positions2
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity43
 —
 8
 6
 14
 14
 3
 5
 15
  7
51
 —
 6
 6
 12
 27
 17
 5
 5
Loss on debt extinguishment(3) (2) —
 —
 —
 —
 —
 —
 —
  —
Non-service net periodic benefit cost(82) —
 —
 —
 —
 —
 —
 —
 —
Other16
 (5) 6
 1
 —
 13
 6
 2
 15
  (11)22
 3
 8
 —
 —
 11
 4
 5
 1
Other, net$377

$395

$(72)
$6

$16

$28
 $9
 $8
 $31
  $(4)$643

$648

$14

$6

$12
 $40

$22
 $10
 $6
_________
(a)Includes investment income and realized gains and losses on sales of investments of the trust funds.
(b)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 1615 — Asset Retirement Obligations of the Exelon 20162017 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
(c)
See Note 12 - Income Taxes for discussion of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position.
The following utility taxes are included in revenues and expenses for the three and nine months ended September 30, 20172018 and 2016.2017. Generation’s utility tax expense represents gross receipts tax related to its retail operations, and the utility registrants'Utility Registrants' utility tax expense represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
 Three Months Ended September 30, 2017
           Successor      
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$245

$35

$65

$35

$22
 $88
 $83

$5

$—
 Three Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$253

$32

$67

$39

$23
 $92
 $87

$5

$—
 Nine Months Ended September 30, 2017
           Successor      
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$682

$97

$181

$95

$69
 $240
 $226

$14

$—
 Nine Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$705

$92

$188

$102

$70
 $253
 $238

$15

$—
 Three Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$245

$35

$65

$35

$22
 $88
 $83

$5

$—

168
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

 Three Months Ended September 30, 2016
           Successor      
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$255

$35

$67

$40

$21
 $92
 $87

$5

$—
                 Successor  Predecessor
 Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016  January 1, 2016 to March 23, 2016
 Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI  PHI
Utility taxes$624

$90

$186

$106

$66
 $240

$14

$—
 $176
  $78
 Nine Months Ended September 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$682

$97

$181

$95

$69
 $240
 $226

$14

$—
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the nine months ended September 30, 20172018 and 2016.2017.
Nine Months Ended September 30, 2017
          Successor      Nine Months Ended September 30, 2018
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization and accretion                                  
Property, plant and equipment(a)
$2,416
 $1,010
 $579
 $194
 $233
 $342
 $153
 $92
 $66
$2,829
 $1,347
 $613
 $204
 $249
 $355
 $161
 $97
 $70
Amortization of regulatory assets(a)
355
 —
 52
 19
 115
 169
 89
 32
 47
412
 —
 83
 20
 109
 200
 125
 38
 37
Amortization of intangible assets, net(a)
43
 36
 —
 —
 —
 —
 —
 —
 —
43
 36
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
19
 19
 —
 —
 —
 —
 —
 —
 —
8
 8
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
816
 816
 —
 —
 —
 —
 —
 —
 —
852
 852
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
350
 350
 —
 —
 —
 —
 —
 —
 —
367
 365
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$3,999

$2,231

$631

$213

$348
 $511
 $242

$124

$113
$4,511

$2,608

$696

$224

$358
 $555
 $286

$135

$107
  Successor  Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016  January 1, 2016 to March 23, 2016Nine Months Ended September 30, 2017
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI  PHIExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization and accretion                                     
Property, plant and equipment(a)
$2,490
 $1,297
 $524
 $181
 $223
 $128
 $82
 $61
 $215
  $94
$2,416
 $1,010
 $579
 $194
 $233
 $342
 $153
 $92
 $66
Amortization of regulatory assets(a)
293
 —
 49
 20
 84
 93
 38
 69
 140
  58
355
 —
 52
 19
 115
 169
 89
 32
 47
Amortization of intangible assets, net(a)
38
 32
 —
 —
 —
 —
 —
 —
 —
  —
43
 36
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
(7) (7) —
 —
 —
 —
 —
 —
 —
  —
19
 19
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
862
 862
 —
 —
 —
 —
 —
 —
 —
  —
816
 816
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
333
 332
 1
 —
 —
 —
 —
 —
 —
  —
350
 350
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$4,009

$2,516

$574

$201

$307
 $221

$120

$130
 $355
  $152
$3,999

$2,231

$631

$213

$348
 $511
 $242

$124

$113
_________
(a)Included in Depreciation and amortization on the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(b)Included in Operating revenues or Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(d)Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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

Table of Contents
 Nine Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:                 
Pension and non-pension postretirement benefit costs$435
 $151
 $133
 $14
 $43
 $51
 $10
 $5
 $10
Loss (gain) from equity method investments22
 23
 —
 —
 —
 (1) —
 —
 —
Provision for uncollectible accounts133
 38
 30
 25
 6
 32
 12
 6
 14
Stock-based compensation costs64
 —
 —
 —
 —
 —
 —
 —
 —
Other decommissioning-related activity(a)
(39) (39) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
4
 4
 —
 —
 —
 —
 —
 —
 —
Amortization of regulatory asset related to debt costs6
 —
 2
 —
 —
 3
 1
 1
 1
Amortization of rate stabilization deferral—
 —
 —
 —
 —
 —
 —
 —
 —
Amortization of debt fair value adjustment(12) (9) —
 —
 —
 (3) —
 —
 —
Discrete impacts from EIMA and FEJA(c)
27
 —
 27
 —
 —
 —
 —
 —
 —
Amortization of debt costs26
 10
 4
 1
 1
 3
 2
 1
 —
Provision for excess and obsolete inventory15
 13
 2
 —
 —
 —
 —
 —
 —
Long-term incentive plan84
 —
 —
 —
 —
 —
 —
 —
 —
Asset retirement costs20
 —
 —
 —
 —
 20
 22
 (1) (1)
Other19
 (4) (11) 1
 (8) 4
 (5) 4
 —
Total other non-cash operating activities$804

$187

$187

$41

$42
 $109
 $42

$16

$24
Non-cash investing and financing activities:              
(Decrease) increase in capital expenditures not paid$(175) $(226) $(28) $4
 $44
 $54
 $15
 $20
 $16
Increase in PPE related to ARO update67
 47
 4
 —
 1
 15
 12
 2
 1
Dividends on stock compensation4
 —
 —
 —
 —
 —
 —

—
 —
Acquisition of land3
 —
 —
 —
 —
 3
 —
 —
 3

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

 Nine Months Ended September 30, 2017
           Successor      
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:                 
Pension and non-pension postretirement benefit costs$482
 $170
 $131
 $21
 $47
 $72
 $19
 $10
 $10
Loss from equity method investments26
 26
 —
 —
 —
 —
 —
 —
 —
Provision for uncollectible accounts103
 31
 25
 17
 4
 26
 11
 1
 14
Stock-based compensation costs76
 —
 —
 —
 —
 —
 —
 —
 —
Other decommissioning-related activity(a)
(213) (213) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
15
 15
 —
 —
 —
 —
 —
 —
 —
Amortization of regulatory asset related to debt costs7
 —
 3
 1
 —
 3
 1
 1
 1
Amortization of rate stabilization deferral(7) —
 —
 —
 7
 (14) (12) (2) —
Amortization of debt fair value adjustment(13) (9) —
 —
 —
 (4) —
 —
 —
Discrete impacts from EIMA and FEJA(c)
(61) —
 (61) —
 —
 —
 —
 —
 —
Amortization of debt costs57
 33
 3
 1
 1
 1
 1
 —
 —
Provision for excess and obsolete inventory

52
 50
 1
 —
 —
 1
 —
 1
 —
Merger-related commitments(d)
—
 —
 —
 —
 —
 (8) (6) (2) —
Severance costs33
 25
 —
 —
 —
 3
 —
 —
 —
Other46
 4
 10
 (2) (7) (14) (6) (3) (4)
Total other non-cash operating activities$603

$132

$112

$38

$52
 $66
 $8

$6

$21
Non-cash investing and financing activities:              
Change in capital expenditures not paid$(101) $20
 $(79) $(29) $16
 $(6) $7
 $14
 $(18)
Fair value of pension obligation transferred in connection with the FitzPatrick acquisition—
 33
 —
 —
 —
 —
 —
 —
 —
Change in PPE related to ARO update(141) (141) —
 —
 —
 —
 —
 —
 —
Indemnification of like-kind exchange position(g)
—
 —
 21
 —
 —
 —
 —
 —
 —
Non-cash financing of capital projects16
 16
 —
 —
 —
 —
 —
 —
 —
Dividends on stock compensation5
 —
 —
 —
 —
 —
 —

—
 —
Dissolution of financing trust due to long-term debt retirement8
 —
 —
 —
 8
 —
 —
 —
 —
Fair value adjustment of long-term debt due to retirement(5) —
 —
 —
 —
 —
 —
 —
 —

170
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

                Successor  Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016  January 1, 2016 to March 23, 2016Nine Months Ended September 30, 2017
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI  PHIExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:                                     
Pension and non-pension postretirement benefit costs$458
 $163
 $124
 $25
 $50
 $24
 $13
 $11
 $58
  $23
$482
 $170
 $131
 $21
 $47
 $72
 $19
 $10
 $10
Loss from equity method investments15
 16
 —
 —
 —
 —
 —
 —
 —
  —
26
 26
 —
 —
 —
 —
 —
 —
 —
Provision for uncollectible accounts107
 14
 31
 24
 12
 15
 12
 18
 27
  16
103
 31
 25
 17
 4
 26
 11
 1
 14
Stock-based compensation costs88
 —
 —
 —
 —
 —
 —
 —
 —
  3
76
 —
 —
 —
 —
 —
 —
 —
 —
Other decommissioning-related activity(a)
(237) (237) —
 —
 —
 —
 —
 —
 —
  —
(213) (213) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
(20) (20) —
 —
 —
 —
 —
 —
 —
  —
15
 15
 —
 —
 —
 —
 —
 —
 —
Amortization of regulatory asset related to debt costs7
 —
 3
 1
 —
 2
 —
 1
 2
  1
7
 —
 3
 1
 —
 3
 1
 1
 1
Amortization of rate stabilization deferral62
 —
 —
 —
 62
 3
 3
 —
 —
  5
(7) —
 —
 —
 7
 (14) (12) (2) —
Amortization of debt fair value adjustment(9) (9) —
 —
 —
 —
 —
 —
 —
  —
(13) (9) —
 —
 —
 (4) —
 —
 —
Discrete impacts from EIMA (c)
(36) —
 (36) —
 —
 —
 —
 —
 —
  —
Discrete impacts from EIMA and FEJA (c)
(61) —
 (61) —
 —
 —
 —
 —
 —
Amortization of debt costs26
 12
 (3) 2
 3
 —
 —
 —
 —
  —
57
 33
 3
 1
 1
 1
 1
 —
 —
Provision for excess and obsolete inventory
74
 70
 4
 —
 —
 1
 1
 1
 —
  1
52
 50
 1
 —
 —
 1
 —
 1
 —
Merger-related commitments (d)(e)
508
 3
 —
 —
 —
 125
 73
 110
 308
  —
Merger-related commitments(d)
—
 —
 —
 —
 —
 (8) (6) (2) —
Severance costs130
 57
 —
 —
 —
 —
 —
 —
 53
  —
33
 25
 —
 —
 —
 3
 —
 —
 —
Asset retirement costs—
 —
 —
 —
 —
 —
 5
 2
 —
  —
Lower of cost or net realizable value inventory adjustment36
 36
 —
 —
 —
 —
 —
 —
 —
  —
Other15
 24
 (1) (3) (18) (2) (8) (5) (7)  (3)46
 4
 10
 (2) (7) (14) (6) (3) (4)
Total other non-cash operating activities$1,224

$129

$122

$49

$109
 $168

$99

$138
 $441
  $46
$603

$132

$112

$38

$52
 $66
 $8

$6

$21
Non-cash investing and financing activities:                                     
Change in capital expenditures not paid$(338) $(289) $(42) $(4) $17
 $15
 $(10) $2
 $(5)  $11
Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash(d)(f)
—
 119
 —
 —
 —
 —
 —
 —
 —
  —
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash(d)(f)
—
 —
 —
 —
 —
 —
 —
 —
 129
  —
Fair value of pension obligation transferred in connection with the PHI Merger—
 —
 —
 —
 —
 —
 —
 —
 53
  —
Assumption of member purchase liability—
 —
 —
 —
 —
 —
 —
 —
 29
  —
Assumption of merger commitment liability—
 —
 —
 —
 —
 33
 —
 —
 33
  —
Change in PPE related to ARO update
476
 476
 —
 —
 —
 —
 —
 —
 —
  —
Indemnification of like-kind exchange position(g)
—
 —
 157
 —
 —
 —
 —
 —
 —
  —
(Decrease) increase in capital expenditures not paid$(101) $20
 $(79) $(29) $16
 $(6) $7
 $14
 $(18)
Fair value of pension obligation transferred in connection with the FitzPatrick acquisition—
 33
 —
 —
 —
 —
 —
 —
 —
Decrease in PPE related to ARO update(141) (141) —
 —
 —
 —
 —
 —
 —
Indemnification of like-kind exchange tax position(e)
—
 —
 21
 —
 —
 —
 —
 —
 —
Non-cash financing of capital projects84
 84
 —
 —
 —
 —
 —
 —
 —
  —
16
 16
 —
 —
 —
 —
 —
 —
 —
Dividends on stock compensation2
 —
 —
 —
 —
 —
 —
 —
 —
  —
5
 —
 —
 —
 —
 —
 —
 —
 —
Dissolution of financing trust due to long-term debt retirement8
 —
 —
 —
 8
 —
 —
 —
 —
Fair value adjustment of long-term debt due to retirement(5) —
 —
 —
 —
 —
 —
 —
 —
_________
(a)Includes the elimination of NDT fund activitydecommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 16 -15 — Asset Retirement Obligations of the Exelon 20162017 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded in Operating revenues.revenues and expenses.
(c)Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 6 — Regulatory Matters for additional information.
(d)
See Note 4 - Mergers, Acquisitions and Dispositions for additional information.
(e)See Note 12 - Income Taxes for additional information on the like-kind exchange tax position.

171
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 and FEJA, which allows for the recovery of distribution costs by a utility through a pre-established performance-based formula rate tariff. Beginning June 1, 2017, also reflects the change in energy efficiency rates pursuant to FEJA, which allows for the recovery of energy efficiency costs by a utility through a pre-established performance-based formula rate tariff. See Note 5 — Regulatory Matters for more information.
(d)See Note 4 — Mergers, Acquisitions and Dispositions for additional information related to the merger with PHI.
(e)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.
(f)Immediately following closing of the PHI Merger, the net assets associated with PHI's unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation.
(g)See Note 12— Income Taxes for discussion of the like-kind exchange tax position.
The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
September 30, 2018Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$1,918
 $1,187
 $124
 $102
 $113
 $153
 $12
 $110
 $11
Restricted cash240
 152
 12
 5
 3
 42
 35
 —
 7
Restricted cash included in other long-term assets163
 —
 144
 —
 —
 19
 —
 —
 19
Total cash, cash equivalents and restricted cash$2,321
 $1,339
 $280
 $107
 $116
 $214
 $47
 $110
 $37
December 31, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$898
 $416
 $76
 $271
 $17
 $30
 $5
 $2
 $2
Restricted cash207
 138
 5
 4
 1
 42
 35
 —
 6
Restricted cash included in other long-term assets85
 —
 63
 —
 —
 23
 —
 —
 23
Total cash, cash equivalents and restricted cash$1,190
 $554
 $144
 $275
 $18
 $95
 $40
 $2
 $31
September 30, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$1,203
 $360
 $257
 $330
 $29
 $137
 $117
 $3
 $5
Restricted cash320
 186
 52
 4
 1
 43
 34
 —
 9
Restricted cash included in other long-term assets22
 —
 —
 —
 —
 22
 —
 —
 22
Total cash, cash equivalents and restricted cash$1,545
 $546
 $309
 $334
 $30
 $202
 $151
 $3
 $36
December 31, 2016Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$635
 $290
 $56
 $63
 $23
 $170
 $9
 $46
 $101
Restricted cash253
 158
 2
 4
 24
 43
 33
 —
 9
Restricted cash included in other long-term assets26
 —
 —
 —
 3
 23
 —
 —
 23
Total cash, cash equivalents and restricted cash$914
 $448
 $58
 $67
 $50
 $236
 $42
 $46
 $133
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K. 
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 20172018 and December 31, 2016.2017.
           Successor      
September 30, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:                 
Accumulated depreciation and amortization$20,591
(a) 
$11,193
(a)  
$4,191

$3,366

$3,351
 $448
 $3,171

$1,231

$1,060
Accounts receivable:                 
Allowance for uncollectible accounts$339

$111

$72

$57

$25
 $74
 $29

$17

$28
          Successor 
    
December 31, 2016Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
September 30, 2018Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:                                  
Accumulated depreciation and amortization$19,169
(b) 
$10,562
(b)  
$3,937

$3,253

$3,254
 $195
 $3,050

$1,175

$1,016
$23,122
(a) 
$12,753
(a)  
$4,557

$3,521

$3,579
 $759
 $3,311

$1,315

$1,121
Accounts receivable:                                  
Allowance for uncollectible accounts$334

$91
 $70

$61

$32
 $80
 $29

$24

$27
$354

$112

$93

$61

$22
 $66
 $25

$16

$25

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

December 31, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:                 
Accumulated depreciation and amortization$21,064
(b) 
$11,428
(b) 
$4,269

$3,411

$3,405
 $487
 $3,177

$1,247

$1,066
Accounts receivable:                 
Allowance for uncollectible accounts$322

$114

$73

$56

$24
 $55
 $21

$16

$18
_________
(a)Includes accumulated amortization of nuclear fuel in the reactor core of $3,303$3,278 million.
(b)Includes accumulated amortization of nuclear fuel in the reactor core of $3,186$3,159 million.
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 one year, to repay past due balances in addition to paying for their ongoing service on a current basis.year. 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 $11 million and $9 million as of September 30, 20172018 and December 31, 2016, respectively.2017. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2018 and December 31, 2017 of $11 million consists of $3 million and $8 million for medium risk and high risk segments, respectively. See Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K for additional information regarding 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 of the Exelon 2016 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2017 of $12 million consists of $3 million and $9 million for medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance 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 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 September 30, 2017 and December 31, 2016 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 of the Exelon 2016 Form 10-K.

172
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

20.19. 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 sixreportable 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.

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

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:
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 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

173
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

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.

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 three and nine months ended September 30, 20172018 and 20162017 is as follows:
Three Months Ended September 30, 20172018 and 20162017
        Successor      
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Generation(a)
 ComEd PECO BGE 
PHI(b)
 
Other(c)
 Intersegment
Eliminations		 Exelon
Operating revenues(d):
               
Operating revenues(c):
               
20182018
Competitive businesses electric revenues$4,741
 $—
 —
 $—
 $—
 $—
 $(306) $4,435
Competitive businesses natural gas revenues397
 —
 —
 —
 —
 —
 —
 397
Competitive businesses other revenues140
 —
 —
 —
 —
 —
 (1) 139
Rate-regulated electric revenues—
 1,598
 700
 645
 1,334
 —
 (7) 4,270
Rate-regulated natural gas revenues—
 —
 57
 86
 24
 —
 (5) 162
Shared service and other revenues—
 —
 —
 —
 3
 458
 (461) —
Total operating revenues$5,278
 $1,598
 $757
 $731
 $1,361
 $458
 $(780) $9,403
2017                              
Competitive businesses electric revenues$4,042
 $—
 $—
 $—
 $—
 $—
 $(295) $3,747
$4,041
 $—
 $—
 $—
 $—
 $—
 $(295) $3,746
Competitive businesses natural gas revenues460
 —
 —
 —
 —
 —
 —
 460
460
 —
 —
 —
 —
 —
 —
 460
Competitive businesses other revenues249
 —
 —
 —
 —
 —
 —
 249
249
 —
 —
 —
 —
 —
 —
 249
Rate-regulated electric revenues—
 1,571
 662
 658
 1,280
 —
 (7) 4,164
—
 1,571
 662
 658
 1,280
 —
 (7) 4,164
Rate-regulated natural gas revenues—
 —
 53
 80
 18
 —
 (2) 149
—
 —
 53
 80
 18
 —
 (2) 149
Shared service and other revenues—
 —
 —
 —
 12
 446
 (458) —
—
 —
 —
 —
 12
 446
 (458) —
2016               
Competitive businesses electric revenues$4,322
 $—
 $—
 $—
 $—
 $—
 $(499) $3,823
Competitive businesses natural gas revenues326
 —
 —
 —
 —
 —
 —
 326
Competitive businesses other revenues387
 —
 —
 —
 —
 —
 (1) 386
Rate-regulated electric revenues—
 1,497
 740
 735
 1,366
 —
 (8) 4,330
Rate-regulated natural gas revenues—
 —
 48
 77
 17
 —
 (5) 137
Shared service and other revenues—
 —
 —
 —
 11
 362
 (373) —
Intersegment revenues(e):
               
Total operating revenues$4,750
 $1,571
 $715
 $738
 $1,310
 $446
 $(762) $8,768
Intersegment revenues(d):
               
2018$308
 $4
 $2
 $6
 $3
 $456
 $(779) $—
2017$294
 $3
 $2
 $3
 $12
 $445
 $(759) $—
294
 3
 2
 3
 12
 445
 (759) —
2016500
 4
 2
 7
 11
 362
 (885) 1
Net income (loss):              
              
2018$300
 $193
 $126
 $63
 $187
 $(69) $—
 $800
2017$348
 $189
 $112
 $62
 $153
 $3
 $—
 $867
346
 189
 112
 62
 153
 3
 —
 865
2016271
 37
 122
 56
 166
 (125) (1) 526
Total assets:              
              
September 30, 2017$47,744
 $29,649
 $11,480
 $8,923
 $21,301
 $10,662
 $(11,286) $118,473
December 31, 201646,974
 28,335
 10,831
 8,704
 21,025
 10,369
 (11,334) 114,904
September 30, 2018$48,207
 $31,119
 $10,621
 $9,541
 $21,957
 $8,418
 $(10,378) $119,485
December 31, 201748,457
 29,726
 10,170
 9,104
 21,247
 8,618
 (10,552) 116,770
               

174
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

___________________
(a)Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the three months ended September 30, 2018 include revenue from sales to PECO of $35 million, sales to BGE of $69 million, sales to Pepco of $46 million, sales to DPL of $26 million and sales to ACE of $10 million in the Mid-Atlantic region, and sales to ComEd of $122 million in the Midwest region, which eliminate upon consolidation. For the three months ended September 30, 2017, intersegment revenues for Generation include revenue from sales to PECO of $31 million, sales to BGE of $98 million, sales to Pepco of $57 million, sales to DPL of $47 million and sales to ACE of $7 million in the Mid-Atlantic region, and sales to ComEd of $54 million in the Midwest region. For the three months ended September 30, 2016, intersegment revenues for Generation include revenue from sales to PECO of $91 million, sales to BGE of $183 million, sales to Pepco of $128 million, sales to DPL of $63 million, and sales to ACE of $15 million in the Mid-Atlantic region, and sales to ComEd of $20 million in the Midwest region.which eliminate upon consolidation.
(b)Amounts included represent activity for PHI's successor period, three months ended September 30, 2017 and 2016. PHI includes the three reportable segments: Pepco, DPL and ACE.
(c)Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(d)(c)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 1918 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 20172018 and 2016.2017.
(e)(d)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.
Successor PHI:
Pepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHIPepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHI
Operating revenues(a):
Operating revenues(a):
Operating revenues(a):
Three Months Ended September 30, 2017 - Successor           
Three Months Ended September 30, 2018           
Rate-regulated electric revenues$604
 $309
 $370
 $—
 $(3) $1,280
$628
 $304
 $406
 $—
 $(4) $1,334
Rate-regulated natural gas revenues—
 18
 —
 —
 —
 18
—
 24
 —
 —
 —
 24
Shared service and other revenues—
 —
 —
 12
 —
 12
—
 —
 —
 103
 (100) 3
Three Months Ended September 30, 2016 - Successor           
Total operating revenues$628
 $328
 $406
 $103
 $(104) $1,361
Three Months Ended September 30, 2017           
Rate-regulated electric revenues$635
 $314
 $421
 $—
 $(4) $1,366
$604
 $309
 $370
 $—
 $(3) $1,280
Rate-regulated natural gas revenues—
 17
 —
 —
 —
 17
—
 18
 —
 —
 —
 18
Shared service and other revenues—
 —
 —
 11
 —
 11
—
 —
 —
 12
 —
 12
Total operating revenues$604
 $327
 $370
 $12
 $(3) $1,310
Intersegment revenues:                      
Three Months Ended September 30, 2017 - Successor$1
 $2
 $—
 $13
 $(4) $12
Three Months Ended September 30, 2016 - Successor1
 2
 1
 11
 (4) 11
Three Months Ended September 30, 2018$2
 $2
 $1
 $103
 $(105) $3
Three Months Ended September 30, 20171
 2
 —
 13
 (4) 12
Net income (loss):                      
Three Months Ended September 30, 2017 - Successor$87
 $31
 $41
 $(18) $12
 $153
Three Months Ended September 30, 2016 - Successor79
 44
 47
 (15) 11
 166
Three Months Ended September 30, 2018$89
 $33
 $61
 $1
 $3
 $187
Three Months Ended September 30, 201787
 31
 41
 (18) 12
 153
Total assets:                      
September 30, 2017 - Successor$7,775
 $4,276
 $3,510
 $10,724
 $(4,984) $21,301
December 31, 2016 - Successor7,335
 4,153
 3,457
 10,804
 (4,724) 21,025
September 30, 2018$8,199
 $4,601
 $3,694
 $10,763
 $(5,300) $21,957
December 31, 20177,832
 4,357
 3,445
 10,600
 (4,987) 21,247
___________________
(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 1918 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 20172018 and 2016.2017.
(b)Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.

The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors for three months ended September 30, 2018 and 2017. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.
175
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Generation total revenues:Competitive Business Revenues (Generation):
            
 Three Months Ended September 30, 2017 Three Months Ended September 30, 2016
 
Revenues
from external
customers(a)

Intersegment
revenues
Total
Revenues
Revenues
from external
customers(a)

Intersegment
revenues
Total
Revenues
Mid-Atlantic$1,421
 $11
 $1,432
 $1,813
 $(13) $1,800
Midwest1,049
 (11) 1,038
 1,163
 1
 1,164
New England482
 (1) 481
 455
 (4) 451
New York434
 (6) 428
 331
 (8) 323
ERCOT308
 6
 314
 289
 6
 295
Other Power Regions348
 (13) 335
 271
 (33) 238
Total Revenues for Reportable Segments4,042
 (14) 4,028
 4,322
 (51) 4,271
Other(b)
709
 14
 723
 713
 51
 764
Total Generation Consolidated Operating Revenues$4,751
 $—
 $4,751
 $5,035
 $—
 $5,035
_________
 Three Months Ended September 30, 2018
 
Revenues from external parties(a)
 Intersegment
revenues
Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$1,397
 $52
 $1,449
 $7
 $1,456
Midwest1,095
 26
 1,121
 (4) 1,117
New England666
 33
 699
 —
 699
New York475
 (6) 469
 —
 469
ERCOT156
 289
 445
 (1) 444
Other Power Regions293
 265
 558
 (45) 513
Total Competitive Businesses Electric Revenues4,082
 659
 4,741
 (43) 4,698
Competitive Businesses Natural Gas Revenues200
 197
 397
 43
 440
Competitive Businesses Other Revenues(c)
130
 10
 140
 —
 140
Total Generation Consolidated Operating Revenues$4,412
 $866
 $5,278
 $—
 $5,278
 Three Months Ended September 30, 2017
 
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$1,397
 $24
 $1,421
 $11
 $1,432
Midwest982
 67
 1,049
 (11) 1,038
New England504
 (22) 482
 (1) 481
New York454
 (21) 433
 (6) 427
ERCOT164
 144
 308
 6
 314
Other Power Regions167
 181
 348
 (13) 335
Total Competitive Businesses Electric Revenues3,668
 373
 4,041
 (14) 4,027
Competitive Businesses Natural Gas Revenues226
 234
 460
 20
 480
Competitive Businesses Other Revenues(c)
207
 42
 249
 (6) 243
Total Generation Consolidated Operating Revenues$4,101
 $649
 $4,750
 $—
 $4,750
__________
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $13 million and $21 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the three months ended September 30, 2017, and 2016, respectively, unrealized mark-to-market gaingains of $52$6 million and $187$52 million for the three months ended September 30, 20172018 and 2016,2017, respectively, and elimination of intersegment revenues.
Generation total revenues
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Revenues net of purchased power and fuel expense:expense (Generation):
           
Three Months Ended September 30, 2017 Three Months Ended September 30, 2016Three Months Ended September 30, 2018 Three Months Ended September 30, 2017
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
Mid-Atlantic$817
 $38
 $855
 $881
 $6
 $887
$746
 $17
 $763
 $817
 $38
 $855
Midwest697
 —
 697
 782
 (1) 781
763
 5
 768
 697
 —
 697
New England151
 (6) 145
 170
 (10) 160
83
 (2) 81
 151
 (6) 145
New York296
 —
 296
 195
 (1) 194
290
 2
 292
 295
 —
 295
ERCOT229
 (111) 118
 144
 (51) 93
161
 (63) 98
 229
 (111) 118
Other Power Regions118
 (50) 68
 143
 (66) 77
143
 (44) 99
 118
 (50) 68
Total Revenues net of purchased power and fuel for Reportable Segments2,308

(129)
2,179

2,315

(123)
2,192
2,186

(85)
2,101

2,307

(129)
2,178
Other(b)
112
 129
 241
 131
 123
 254
112
 85
 197
 112
 129
 241
Total Generation Revenues net of purchased power and fuel expense$2,420

$—

$2,420

$2,446

$—

$2,446
$2,298

$—

$2,298

$2,419

$—

$2,419
___________________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $19 million and $22 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the three months ended September 30, 2017, and 2016, respectively, unrealized mark-to-market gains of $73$71 million and $88$73 million for the three months ended September 30, 20172018 and 2016,2017, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 78 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $6$18 million and $28$6 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 20172018, and 2016,2017, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

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

Electric and Gas Revenue by Customer Class (the Utility Registrants):
Table of Contents
 Three Months Ended September 30, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$861
 $458
 $366
 $726
 $306
 $180
 $240
Small commercial & industrial391
 108
 68
 140
 39
 48
 53
Large commercial & industrial131
 64
 117
 303
 230
 25
 48
Public authorities & electric railroads11
 7
 7
 14
 8
 3
 3
Other(a)
212
 59
 91
 156
 47
 47
 63
Total rate-regulated electric revenues(b)
1,606
 696
 649
 1,339
 630
 303
 407
Rate-regulated natural gas revenues             
Residential—
 36
 46
 8
 —
 8
 —
Small commercial & industrial—
 15
 8
 5
 —
 5
 —
Large commercial & industrial—
 —
 17
 2
 —
 2
 —
Transportation—
 5
 —
 3
 —
 3
 —
Other(c)
—
 1
 12
 6
 —
 6
 —
Total rate-regulated natural gas revenues(d)
—
 57
 83
 24
 —
 24
 —
Total rate-regulated revenues from contracts with customers1,606
 753
 732
 1,363
 630
 327
 407
              
Other revenues             
Revenues from alternative revenue programs(15) 1
 (6) (5) (4) —
 (1)
Other rate-regulated electric revenues(e)
7
 3
 4
 3
 2
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 1
 —
 —
 —
 —
Total other revenues(8) 4
 (1) (2) (2) 1
 (1)
Total rate-regulated revenues for reportable segments$1,598
 $757
 $731
 $1,361
 $628
 $328
 $406

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

 Three Months Ended September 30, 2017
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$816
 $434
 $352
 $687
 $291
 $185
 $211
Small commercial & industrial366
 106
 65
 140
 37
 50
 53
Large commercial & industrial119
 59
 114
 288
 211
 28
 49
Public authorities & electric railroads11
 7
 8
 14
 8
 3
 3
Other(a)
235
 53
 85
 147
 52
 43
 54
Total rate-regulated electric revenues(b)
1,547
 659
 624
 1,276
 599
 309
 370
Rate-regulated natural gas revenues             
Residential—
 33
 44
 8
 —
 8
 —
Small commercial & industrial—
 14
 8
 3
 —
 3
 —
Large commercial & industrial—
 —
 19
 1
 —
 1
 —
Transportation—
 5
 —
 3
 —
 3
 —
Other(c)
—
 1
 3
 3
 —
 3
 —
Total rate-regulated natural gas revenues(d)
—
 53
 74
 18
 —
 18
 —
Total rate-regulated revenues from contracts with customers1,547
 712
 698
 1,294
 599
 327
 370
              
Other revenues             
Revenues from alternative revenue programs16
 —
 36
 2
 3
 (1) —
Other rate-regulated electric revenues(e)
8
 3
 3
 3
 2
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 1
 —
 —
 —
 —
Other revenues(f)
—
 —
 —
 11
 —
 —
 —
Total other revenues24
 3
 40
 16
 5
 —
 —
Total rate-regulated revenues for reportable segments$1,571
 $715
 $738
 $1,310
 $604
 $327
 $370
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $4 million, $2 million, $1 million, $3 million, $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the three months ended September 30, 2018 and $3 million, $1 million, $1 million, $1 million $1 million, $2 million and less than $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the three months ended September 30, 2017.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of less than $1 million and $5 million at PECO and BGE, respectively, for the three months ended September 30, 2018 and less than $1 million and $2 million at PECO and BGE, respectively, for the three months ended September 30, 2017.
(e)Includes late payment charge revenues.
(f)Includes operating revenues from affiliates of $11 million at PHI for the three months ended September 30, 2017.

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

Nine Months Ended September 30, 20172018 and 20162017
        Successor      
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Generation(a)
 ComEd PECO BGE 
PHI(b)
 
Other(c)
 Intersegment
Eliminations		 Exelon
Operating revenues(d):
Operating revenues(c):
Operating revenues(c):
2018               
Competitive businesses electric revenues$13,190
 $—
 $—
 $—
 $—
 $—
 $(969) $12,221
Competitive businesses natural gas revenues1,839
 —
 —
 —
 —
 —
 (8) 1,831
Competitive businesses other revenues339
 —
 —
 —
 —
 —
 (4) 335
Rate-regulated electric revenues—
 4,508
 1,893
 1,850
 3,549
 —
 (34) 11,766
Rate-regulated natural gas revenues—
 —
 382
 519
 129
 —
 (13) 1,017
Shared service and other revenues—
 —
 —
 —
 10
 1,398
 (1,408) —
Total operating revenues$15,368
 $4,508
 $2,275
 $2,369
 $3,688
 $1,398
 $(2,436) $27,170
2017                              
Competitive businesses electric revenues$11,485
 $—
 $—
 $—
 $—
 $—
 $(888) $10,597
$11,514
 $—
 $—
 $—
 $—
 $—
 $(888) $10,626
Competitive businesses natural gas revenues1,807
 —
 —
 —
 —
 —
 —
 1,807
1,807
 —
 —
 —
 —
 —
 —
 1,807
Competitive businesses other revenues520
 —
 —
 —
 —
 —
 —
 520
522
 —
 —
 —
 —
 —
 —
 522
Rate-regulated electric revenues—
 4,227
 1,802
 1,895
 3,417
 —
 (23) 11,318
—
 4,227
 1,802
 1,895
 3,417
 —
 (23) 11,318
Rate-regulated natural gas revenues—
 —
 339
 468
 105
 —
 (6) 906
—
 —
 339
 468
 105
 —
 (6) 906
Shared service and other revenues—
 —
 —
 —
 35
 1,316
 (1,350) 1
—
 —
 —
 —
 35
 1,316
 (1,350) 1
2016               
Competitive businesses electric revenues$11,677
 $—
 $—
 $—
 $—
 $—
 $(1,118) $10,559
Competitive businesses natural gas revenues1,515
 —
 —
 —
 —
 —
 —
 1,515
Competitive businesses other revenues171
 —
 —
 —
 —
 —
 (2) 169
Rate-regulated electric revenues—
 4,031
 1,971
 1,998
 2,485
 —
 (24) 10,461
Rate-regulated natural gas revenues—
 —
 322
 423
 46
 —
 (10) 781
Shared service and other revenues—
 —
 —
 —
 34
 1,166
 (1,199) 1
Intersegment revenues(e):
               
Total operating revenues$13,843
 $4,227
 $2,141
 $2,363
 $3,557
 $1,316
 $(2,267) $25,180
Intersegment revenues(d):
               
2018$981
 $23
 $5
 $18
 $11
 $1,392
 $(2,430) $—
2017$888
 $12
 $5
 $12
 $35
 $1,312
 $(2,262) $2
888
 12
 5
 12
 35
 1,312
 (2,262) 2
20161,121
 12
 5
 16
 34
 1,166
 (2,351) 3
Net income (loss):                              
2018$667
 $523
 $336
 $242
 $336
 $(125) $—
 $1,979
2017$491
 $447
 $327
 $231
 $359
 $58
 $(2) $1,911
508
 447
 327
 231
 359
 58
 (2) 1,928
2016556
 297
 346
 191
 (91) (340) (3) 956

177
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

___________________
(a)Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the nine months ended September 30, 2018 include revenue from sales to PECO of $97 million, sales to BGE of $198 million, sales to Pepco of $143 million, sales to DPL of $103 million and sales to ACE of $21 million in the Mid-Atlantic region, and sales to ComEd of $419 million in the Midwest region, which eliminate upon consolidation. For the nine months ended September 30, 2017, intersegment revenues for Generation include revenue from sales to PECO of $111 million, sales to BGE of $330 million, sales to Pepco of $209 million, sales to DPL of $138 million and sales to ACE of $23 million in the Mid-Atlantic region, and sales to ComEd of $77 million in the Midwest region. For the nine months ended September 30, 2016, intersegment revenues for Generation include revenue from sales to PECO of $234 million and sales to BGE of $489 million in the Mid-Atlantic region, and sales to ComEd of $38 million in the Midwest region. For the Successor period of March 24, 2016 to September 30, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $223 million, sales to DPL of $109 million, and sales to ACE of $28 million in the Mid-Atlantic region.which eliminate upon consolidation.
(b)Amounts included represent activity for PHI's successor period, nine months ended September 30, 2017 and March 24, 2016 through September 30, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor period, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016.
(c)Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(d)(c)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 1918 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 20172018 and 2016.2017.

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

(e)(d)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.
Successor and Predecessor PHI:
Pepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHIPepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHI
Operating revenues(a):
                      
Nine Months Ended September 30, 2017 - Successor           
Nine Months Ended September 30, 2018           
Rate-regulated electric revenues$1,649
 $866
 $915
 $—
 $(13) $3,417
$1,708
 $872
 $981
 $—
 $(12) $3,549
Rate-regulated natural gas revenues—
 105
 —
 —
 —
 105
—
 129
 —
 —
 —
 129
Shared service and other revenues—
 —
 —
 37
 (2) 35
—
 —
 —
 326
 (316) 10
March 24, 2016 to September 30, 2016 - Successor           
Total operating revenues$1,708
 $1,001
 $981
 $326
 $(328) $3,688
Nine Months Ended September 30, 2017           
Rate-regulated electric revenues$1,184
 $593
 $714
 $3
 $(9) $2,485
$1,649
 $866
 $915
 $—
 $(13) $3,417
Rate-regulated natural gas revenues—
 46
 —
 —
 —
 46
—
 105
 —
 —
 —
 105
Shared service and other revenues—
 —
 —
 34
 —
 34
—
 —
 —
 37
 (2) 35
January 1, 2016 to March 23, 2016 - Predecessor           
Rate-regulated electric revenues$511
 $279
 $268
 $42
 $(4) $1,096
Rate-regulated natural gas revenues—
 56
 —
 1
 —
 57
Shared service and other revenues—
 —
 —
 —
 —
 —
Total operating revenues$1,649
 $971
 $915
 $37
 $(15) $3,557
Intersegment revenues:                      
Nine Months Ended September 30, 2017 - Successor$4
 $6
 $2
 $37
 $(14) $35
March 24, 2016 to September 30, 2016 - Successor2
 4
 2
 35
 (9) 34
January 1, 2016 to March 23, 2016 - Predecessor1
 2
 1
 —
 (4) —
Nine Months Ended September 30, 2018$5
 $6
 $2
 $325
 $(327) $11
Nine Months Ended September 30, 20174
 6
 2
 37
 (14) 35
Net income (loss):                      
Nine Months Ended September 30, 2017 - Successor$188
 $107
 $77
 $(48) $35
 $359
March 24, 2016 to September 30, 2016 - Successor(12) (42) (55) (16) 34
 (91)
January 1, 2016 to March 23, 2016 - Predecessor32
 26
 5
 (44) —
 19
Nine Months Ended September 30, 2018$174
 $90
 $76
 $(15) $11
 $336
Nine Months Ended September 30, 2017188
 107
 77
 (48) 35
 359
___________________
(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 1918 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 20172018 and 2016.2017.
(b)Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.  For the predecessor period presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger. 

The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors for nine months ended September 30, 2018 and 2017. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants but exclude any intercompany revenues.
178
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Generation total revenues:Competitive Business Revenues (Generation):
Nine Months Ended September 30, 2018
Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016
Revenues from external parties(a)
 
Intersegment
Revenues
 
Total
Revenues
Revenues
from external
customers(a)
 Intersegment
revenues		 Total
Revenues		 
Revenues
from external
customers(a)
 Intersegment
revenues		 Total
Revenues		Contracts with customers 
Other(b)
 Total 
Mid-Atlantic$4,207
 $15
 $4,222
 $4,776
 $(40) $4,736
$3,971
 $191
 $4,162
 $17
 $4,179
Midwest3,158
 (17) 3,141
 3,330
 13
 3,343
3,432
 169
 3,601
 (8) 3,593
New England1,469
 (8) 1,461
 1,278
 (6) 1,272
1,943
 87
 2,030
 (4) 2,026
New York1,095
 (14) 1,081
 906
 (33) 873
1,305
 (37) 1,268
 1
 1,269
ERCOT749
 4
 753
 659
 6
 665
470
 459
 929
 1
 930
Other Power Regions807
 (28) 779
 728
 (42) 686
713
 487
 1,200
 (112) 1,088
Total Revenues for Reportable Segments11,485

(48)
11,437

11,677

(102)
11,575
Other(b)
2,327
 48
 2,375
 1,686
 102
 1,788
Total Competitive Businesses Electric Revenues11,834
 1,356
 13,190
 (105) 13,085
Competitive Businesses Natural Gas Revenues1,016
 823
 1,839
 105
 1,944
Competitive Businesses Other Revenues(c)
385
 (46) 339
 —
 339
Total Generation Consolidated Operating Revenues$13,812

$—

$13,812

$13,363

$—

$13,363
$13,235
 $2,133
 $15,368
 $—
 $15,368
_________
 Nine Months Ended September 30, 2017
 
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$4,260
 $(53) $4,207
 $15
 $4,222
Midwest2,948
 210
 3,158
 (17) 3,141
New England1,555
 (86) 1,469
 (8) 1,461
New York1,161
 (37) 1,124
 (14) 1,110
ERCOT520
 229
 749
 4
 753
Other Power Regions439
 368
 807
 (28) 779
Total Competitive Businesses Electric Revenues10,883
 631
 11,514
 (48) 11,466
Competitive Businesses Natural Gas Revenues1,237
 570
 1,807
 52
 1,859
Competitive Businesses Other Revenues(c)
588
 (66) 522
 (4) 518
Total Generation Consolidated Operating Revenues$12,708
 $1,135
 $13,843
 $—
 $13,843
__________
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $30 million and $10 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the nine months ended September 30, 2017, and 2016, respectively, unrealized mark-to-market losses of $47$96 million and $366$47 million for the nine months ended September 30, 20172018 and 2016,2017, respectively, and elimination of intersegment revenues.
Generation total revenues
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Revenues net of purchased power and fuel expense:expense (Generation):
Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016Nine Months Ended September 30, 2018 Nine Months Ended September 30, 2017
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
Mid-Atlantic$2,330
 $81
 $2,411
 $2,541
 $15
 $2,556
$2,303
 $45
 $2,348
 $2,330
 $81
 $2,411
Midwest2,129
 11
 2,140
 2,225
 4
 2,229
2,381
 19
 2,400
 2,129
 11
 2,140
New England423
 (20) 403
 373
 (23) 350
310
 (12) 298
 423
 (20) 403
New York679
 (1) 678
 607
 (15) 592
832
 9
 841
 708
 (1) 707
ERCOT446
 (188) 258
 335
 (104) 231
396
 (180) 216
 446
 (188) 258
Other Power Regions359
 (139) 220
 357
 (104) 253
430
 (121) 309
 359
 (139) 220
Total Revenues net of purchased power and fuel expense for Reportable Segments6,366

(256)
6,110

6,438

(227)
6,211
6,652

(240)
6,412

6,395

(256)
6,139
Other(b)
160
 256
 416
 316
 227
 543
164
 240
 404
 162
 256
 418
Total Generation Revenues net of purchased power and fuel expense$6,526

$—

$6,526

$6,754

$—

$6,754
$6,816

$—

$6,816

$6,557

$—

$6,557
___________________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $41 million and $15 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the nine months ended September 30, 2017, and 2016, respectively, unrealized mark-to-market losses of $161$104 million and $113$161 million for the nine months ended September 30, 20172018 and 2016,2017, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 78 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $8$53 million and $38$8 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 20172018 and 2016,2017, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

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

Electric and Gas Revenue by Customer Class (the Utility Registrants):
 Nine Months Ended September 30, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$2,277
 $1,199
 $1,054
 $1,839
 $792
 $513
 $534
Small commercial & industrial1,132
 306
 196
 370
 104
 138
 128
Large commercial & industrial411
 174
 325
 845
 632
 74
 139
Public authorities & electric railroads36
 21
 21
 44
 24
 10
 10
Other(a)
656
 181
 246
 446
 145
 129
 174
Total rate-regulated electric revenues(b)
4,512
 1,881
 1,842
 3,544
 1,697
 864
 985
Rate-regulated natural gas revenues             
Residential—
 259
 345
 68
 —
 68
 —
Small commercial & industrial—
 102
 55
 31
 —
 31
 —
Large commercial & industrial—
 1
 88
 7
 —
 7
 —
Transportation—
 16
 —
 12
 —
 12
 —
Other(c)
—
 4
 49
 11
 —
 11
 —
Total rate-regulated natural gas revenues(d)
—
 382
 537
 129
 —
 129
 —
Total rate-regulated revenues from contracts with customers4,512
 2,263
 2,379
 3,673
 1,697
 993
 985
              
Other revenues             
Revenues from alternative revenue programs(27) 2
 (23) 7
 6
 5
 (4)
Other rate-regulated electric revenues(e)
23
 10
 10
 8
 5
 3
 —
Other rate-regulated natural gas revenues(e)
—
 —
 3
 —
 —
 —
 —
Total other revenues(4) 12
 (10) 15
 11
 8
 (4)
Total rate-regulated revenues for reportable segments$4,508
 $2,275
 $2,369
 $3,688
 $1,708
 $1,001
 $981

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

 Nine Months Ended September 30, 2017
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$2,071
 $1,147
 $1,038
 $1,740
 $751
 $505
 $484
Small commercial & industrial1,035
 303
 193
 373
 105
 139
 129
Large commercial & industrial346
 168
 329
 814
 593
 78
 143
Public authorities & electric railroads33
 23
 23
 45
 24
 11
 10
Other(a)
671
 151
 222
 398
 148
 121
 140
Total rate-regulated electric revenues(b)
4,156
 1,792
 1,805
 3,370
 1,621
 854
 906
Rate-regulated natural gas revenues             
Residential—
 225
 289
 57
 —
 57
 —
Small commercial & industrial—
 90
 51
 25
 —
 25
 —
Large commercial & industrial—
 —
 82
 5
 —
 5
 —
Transportation—
 16
 —
 11
 —
 11
 —
Other(c)
—
 8
 20
 7
 —
 7
 —
Total rate-regulated natural gas revenues(d)
—
 339
 442
 105
 —
 105
 —
Total rate-regulated revenues from contracts with customers4,156
 2,131
 2,247
 3,475
 1,621
 959
 906
              
Other revenues             
Revenues from alternative revenue programs48
 —
 102
 41
 23
 9
 9
Other rate-regulated electric revenues(e)
23
 10
 11
 8
 5
 3
 —
Other rate-regulated natural gas revenues(e)
—
 —
 3
 —
 —
 —
 —
Other revenues(f)
—
 —
 —
 33
 —
 —
 —
Total other revenues71
 10
 116
 82
 28
 12
 9
Total rate-regulated revenues for reportable segments$4,227
 $2,141
 $2,363
 $3,557
 $1,649
 $971
 $915
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $23 million, $5 million, $5 million, $11 million, $5 million, $6 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the nine months ended September 30, 2018 and $12 million, $4 million, $5 million, $2 million, $4 million, $6 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the nine months ended September 30, 2017.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of less than $1 million and $13 million at PECO and BGE, respectively, for the nine months ended September 30, 2018 and less than $1 million and $7 million at PECO and BGE, respectively, for the nine months ended September 30, 2017.
(e)Includes late payment charge revenues.
(f)Includes operating revenues from affiliates of $33 million at PHI for the nine months ended September 30, 2017.

Table of Contents


Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations
(Dollars in millions except per share data, unless otherwise noted)
Exelon
Executive Overview
Exelon, 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 natural gas 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 natural 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 20 -19 — 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 corporate governance support services including corporate strategy and development, legal, human resources, information technology, finance, real estate, security, corporate communications and

Table of Contents

supply at cost. The costs of these services are directly charged or allocated to the applicable operating segments. The services are provided pursuant to service agreements. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.
PHI Service Company,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 CompanyPHISCO and the participating operating subsidiaries.
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

180
Table of Contents


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.

Table of Contents

Financial Results of Operations
GAAP Results of Operations
The following tables set forth Exelon's GAAP consolidated results of operations for the three and nine months ended September 30, 20172018 compared to the same period in 2016. The 2016 amounts include the operations of PHI, Pepco, DPL and ACE from March 24, 2016 through September 30, 2016.2017. All amounts presented below are before the impact of income taxes, except as noted.
Three Months Ended September 30, Favorable
(Unfavorable)
Variance		Three Months Ended September 30, Favorable
(Unfavorable)
Variance
2017 2016 2018 2017 
Generation ComEd PECO BGE PHI Other Exelon 
Exelon(b)
 Generation ComEd PECO BGE PHI Other Exelon Exelon 
Operating revenues$4,751
 $1,571
 $715
 $738
 $1,310
 $(316) $8,769
 $9,002
 $(233)$5,278
 $1,598
 $757
 $731
 $1,361
 $(322) $9,403
 $8,768
 $635
Purchased power and fuel2,331
 529
 235
 269
 473
 (295) 3,542
 3,754
 212
Revenue net of purchased power and fuel(a)
2,420
 1,042
 480
 469
 837
 (21) 5,227
 5,248
 (21)
Purchased power and fuel expense2,980
 619
 263
 272
 509
 (311) 4,332
 3,542
 (790)
Revenue net of purchased power and fuel expense(a)
2,298
 979
 494
 459
 852
 (11) 5,071
 5,226
 (155)
Other operating expenses                                  
Operating and maintenance1,374
 346
 197
 175
 251
 (43) 2,300
 2,338
 38
1,370
 337
 219
 182
 292
 (54) 2,346
 2,275
 (71)
Depreciation and amortization410
 212
 72
 109
 179
 20
 1,002
 1,195
 193
468
 237
 75
 110
 192
 23
 1,105
 1,002
 (103)
Taxes other than income141
 80
 42
 61
 122
 10
 456
 449
 (7)143
 82
 46
 64
 123
 11
 469
 456
 (13)
Total other operating expenses1,925
 638
 311
 345
 552
 (13) 3,758
 3,982
 224
1,981
 656
 340
 356
 607
 (20) 3,920
 3,733
 (187)
(Loss) Gain on sales of assets(2) —
 —
 —
 —
 1
 (1) 1
 (2)
(Loss) gain on sales of assets and businesses(6) —
 —
 —
 —
 1
 (5) (1) (4)
Bargain purchase gain7
 —
 —
 —
 —
 —
 7
 —
 7
—
 —
 —
 —
 —
 —
 —
 7
 (7)
Operating income (loss)500
 404
 169
 124
 285
 (7) 1,475
 1,267
 208
Operating income311
 323
 154
 103
 245
 10
 1,146
 1,499
 (353)
Other income and (deductions)                                  
Interest expense, net(113) (89) (31) (26) (62) (65) (386) (516) 130
(101) (85) (32) (27) (65) (83) (393) (386) (7)
Other, net209
 5
 2
 4
 13
 4
 237
 120
 117
179
 7
 2
 5
 11
 (10) 194
 210
 (16)
Total other income and (deductions)96
 (84) (29) (22) (49) (61) (149) (396) 247
78
 (78) (30) (22) (54) (93) (199) (176) (23)
Income (loss) before income taxes596
 320
 140
 102
 236
 (68) 1,326
 871
 455
389
 245
 124
 81
 191
 (83) 947
 1,323
 (376)
Income taxes240
 131
 28
 40
 83
 (70) 452
 340
 (112)78
 52
 (2) 18
 4
 (13) 137
 451
 314
Equity in (losses) earnings of unconsolidated affiliates(8) —
 —
 —
 —
 1
 (7) (5) (2)(11) —
 —
 —
 —
 1
 (10) (7) (3)
Net income348
 189
 112
 62
 153
 3
 867
 526
 341
Net income attributable to noncontrolling interests and preference stock dividends43
 —
 —
 —
 —
 —
 43
 36
 (7)
Net income attributable to common shareholders$305
 $189
 $112
 $62
 $153
 $3
 $824
 $490
 $334
Net income (loss)300
 193
 126
 63
 187
 (69) 800
 865
 (65)
Net income attributable to noncontrolling interests66
 —
 —
 —
 —
 1
 67
 42
 (25)
Net income (loss) attributable to common shareholders$234
 $193
 $126
 $63
 $187
 $(70) $733
 $823
 $(90)

Table of Contents

 Nine Months Ended September 30, 
Favorable
(Unfavorable)
Variance
 2018 2017 
 Generation ComEd PECO BGE PHI Other Exelon Exelon 
Operating revenues$15,368
 $4,508
 $2,275
 $2,369
 $3,688
 $(1,038) $27,170
 $25,180
 $1,990
Purchased power and fuel expense8,552
 1,702
 818
 881
 1,410
 (989) 12,374
 10,527
 (1,847)
Revenue net of purchased power and fuel expense(a)
6,816

2,806

1,457

1,488

2,278
 (49)
14,796

14,653
 143
Other operating expenses        

        
Operating and maintenance4,126
 974
 686
 578
 857
 (185) 7,036
 7,658
 622
Depreciation and amortization1,383
 696
 224
 358
 555
 68
 3,284
 2,814
 (470)
Taxes other than income414
 238
 125
 188
 343
 34
 1,342
 1,313
 (29)
Total other operating expenses5,923

1,908

1,035

1,124

1,755
 (83)
11,662

11,785
 123
Gain on sales of assets and businesses48
 5
 1
 1
 —
 —
 55
 4
 51
Bargain purchase gain—
 —
 —
 —
 —
 —
 —
 233
 (233)
Operating income941

903

423

365

523
 34

3,189

3,105
 84
Other income and (deductions)                 
Interest expense, net(305) (261) (96) (78) (193) (205) (1,138) (1,194) 56
Other, net164
 21
 4
 14
 33
 (24) 212
 643
 (431)
Total other income and (deductions)(141)
(240)
(92)
(64)
(160) (229)
(926)
(551) (375)
Income (loss) before income taxes800
 663
 331
 301
 363
 (195) 2,263
 2,554
 (291)
Income taxes110
 140
 (5) 59
 28
 (70) 262
 601
 339
Equity in (losses) earnings of unconsolidated affiliates(23) —
 —
 —
 1
 —
 (22) (25) 3
Net income (loss)667

523

336

242

336

(125)
1,979

1,928
 51
Net income attributable to noncontrolling interests120
 —
 —
 —
 —
 1
 121
 21
 (100)
Net income (loss) attributable to common shareholders$547

$523

$336

$242

$336
 $(126)
$1,858

$1,907
 $(49)
_________
(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 their 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.
(b)As a result of the PHI Merger, Exelon includes the consolidated results of PHI, Pepco, DPL and ACE from July 1, 2016 through September 30, 2016.

181
Table of Contents


 Nine Months Ended September 30, 
Favorable
(Unfavorable)
Variance
 2017 2016 
 Generation ComEd PECO BGE PHI Other Exelon 
Exelon(b)
 
Operating revenues$13,812
 $4,227
 $2,141
 $2,363
 $3,557
 $(951) $25,149
 $23,486
 $1,663
Purchased power and fuel expense7,286
 1,241
 719
 853
 1,318
 (890) 10,527
 9,462
 (1,065)
Revenue net of purchased power and fuel expense(a)
6,526

2,986

1,422

1,510

2,239
 (61)
14,622

14,024
 598
Other operating expenses        
        
Operating and maintenance4,871
 1,096
 595
 532
 774
 (136) 7,732
 7,677
 (55)
Depreciation and amortization1,046
 631
 213
 348
 511
 65
 2,814
 2,821
 7
Taxes other than income425
 223
 116
 180
 344
 25
 1,313
 1,168
 (145)
Total other operating expenses6,342

1,950

924

1,060

1,629
 (46)
11,859

11,666
 (193)
Gain on sales of assets3
 —
 —
 —
 1
 —
 4
 41
 (37)
Bargain purchase gain233
 —
 —
 —
 —
 —
 233
 —
 233
Operating income (loss)420

1,036

498

450

611
 (15)
3,000

2,399
 601
Other income and (deductions)                 
Interest expense, net(342) (275) (93) (80) (183) (221) (1,194) (1,179) (15)
Other, net648
 14
 6
 12
 40
 5
 725
 377
 348
Total other income and (deductions)306

(261)
(87)
(68)
(143) (216)
(469)
(802) 333
Income (loss) before income taxes726
 775
 411
 382
 468
 (231) 2,531
 1,597
 934
Income taxes209
 328
 84
 151
 109
 (286) 595
 625
 30
Equity in (losses) earnings of unconsolidated affiliates(26) —
 —
 —
 —
 1
 (25) (16) (9)
Net income491

447

327

231

359

56

1,911

956
 955
Net income attributable to noncontrolling interests and preference stock dividends12
 —
 —
 —
 —
 —
 12
 26
 14
Net income attributable to common shareholders$479

$447

$327

$231

$359
 $56

$1,899

$930
 $969
_________
(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 their 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.
(b)As a result of the PHI Merger, Exelon includes the consolidated results of PHI, Pepco, DPL and ACE from March 24, 2016 through September 30, 2016.
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016. 2017.Exelon’s Net income attributable to common shareholders was $824$733 million for the three months ended September 30, 2018 as compared to $823 million for the three months ended September 30, 2017, as compared to $490 million for the three months ended September 30, 2016, and diluted earnings per average common share were $0.85$0.76 for the three months ended September 30, 20172018 as compared to $0.53 $0.85for the three months ended September 30, 2016.2017.

Table of Contents

Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $21$155 million for the three months ended September 30, 2017 as2018 compared to the same period in 2016. The quarter-over-quarter decrease in Revenue2017 primarily due to the following factors:
Decrease of $121 million at Generation primarily due to the absence of EGTP revenues net of purchased power and fuel expense was primarily due toresulting from its deconsolidation in the following unfavorable factors:
Decreasefourth quarter of $36 million at PECO primarily due to unfavorable weathers conditions;
Decrease of $15 million at Generation due to mark-to-market gains of $73 million in 2017, compared to $88 million in 2016; and
Decrease of $11 million at Generation due to the unfavorable impacts of lower load volumes delivered due to mild weather and lower realized energy prices, lower energy efficiency revenues and decreased revenues related to Exelon's ratable hedging strategy,the sale of Generation's electrical contracting business in 2018 and increased nuclear outage days, partially offset by the impact of the New York CES,Illinois ZES and increased capacity prices, increased nuclear volumesprices;
Decrease of $113 million across all Utility Registrants, primarily as a resultreflecting lower revenues resulting from the anticipated pass back of the acquisition of FitzPatrick and decreased nuclear outage days, and the addition of two combined-cycle gas turbines in Texas.

182
Table of Contents


The quarter-over-quarter decrease in Revenue net of purchase power and fuel expense wasTCJA tax savings through customer rates, partially offset by the following favorable factors:
Increase of $26 millionregulatory rate increases at PHI primarily due to increased distribution revenue as a result of rate increases;ComEd, Pepco, DPL and ACE; and
Increase of $17$58 million at BGEPECO, DPL and ACE primarily due to increased transmission revenue as a result of rate increases.favorable weather conditions and volumes within their respective service territories.
Operating and maintenance expense decreasedincreased by $38$71 million for the three months ended September 30, 20172018 as compared to the same period in 20162017 primarily due to the following favorable factors:
DecreaseIncrease of $32$84 million at ExelonGeneration due to a charge associated with a remeasurement of the net recoveryOyster Creek ARO;
Increase of $2$40 million at Generation due to higher nuclear refueling outage costs;
Increase of merger-related costs in 2017 compared$22 million at Pepco due to merger-related costsa charge associated with a remeasurement of $30 million in 2016;the Buzzard Point ARO; and
Decrease of $31 million at ComEd primarily due to the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act.
The quarter-over-quarter decrease in Operating and maintenance expense was partially offset by an increase of $38$50 million at Generation primarily due to the announcement of the early retirement of Generation's TMI nuclear facility in 2017 compared to the previous decision to early retire Generation's Clinton and Quad Cities nuclear facilities in 2016 and higher asset impairment charges, partially offset by decreased nuclear refueling outage costs and labor, contracting and materials expense.expense due to decreased spending related to energy efficiency projects and decreased costs related to the sale of Generation's electrical contracting business in 2018.
Depreciation and amortization expense decreasedincreased by $193$103 million for the three months ended September 30, 2018 as compared to the same period in 2017 primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities, partially offset by increased depreciation expense as a result of ongoing capital expenditures across all operating companies, for the three months ended September 30, 2017 as compared to the same period in 2016.
Taxes other than income increased by $7 millionprimarilyaccelerated depreciation and amortization due to Generation's decision to early retire the Oyster Creek and TMI nuclear facilities, increased property taxesamortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues), partially offset by certain regulatory assets that became fully amortized as a result of the addition of FitzPatrick at GenerationDecember 31, 2017 for the three months ended September 30, 2017 as compared to the same period in 2016.BGE.
Gain on sales of assets remained relatively consistent for the three months ended September 30, 2017 as compared to the same period in 2016.
Bargain purchase gain increased by $7 million due to a measurement period adjustment to the bargain purchase gain for the FitzPatrick acquisition for the three months ended September 30, 2017 as compared to the same period in 2016.
Interest expense,Other, net decreased by $130$16 million primarily due to additional interest recorded in the third quarter 2016 related to Exelon's like-kind exchange tax position, partially offset by the the impact of project in-service dates on the capitalization of interestlower net unrealized and higher outstanding debt at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.
Other, net increased by $117 million primarily due to the penalty recorded in the third quarter of 2016 related to Exelon's like-kind exchange tax position and higher net realized gains on NDT funds at Generation for the three months ended September 30, 2017 as2018 compared to the same period in 2016.2017.
Exelon’s effective income tax rates for the three months ended September 30, 2018 and 2017 were 14.5% and 2016 were 34.1% and 39.0%, respectively. The decrease in the effective income tax rate for the three months ended September 30, 2018 compared to the same period in 2017 is primarily related to tax savings due to the lower federal income tax rate as a result of the TCJA at all Registrants, which is predominantly offset in Operating revenues at the Utility Registrants for the anticipated pass back of the tax savings through customer rates. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on TCJA's impact on regulatory proceedings.

Table of Contents

Nine Months Ended September 30, 20172018 Compared to Nine Months Ended September 30, 2016.    2017.Exelon’s Net income attributable to common shareholders was $1,899$1,858 million for the nine months ended September 30, 2018 compared to $1,907 million for the nine months ended September 30, 2017, as compared to $930 million for the nine months ended September 30, 2016, and diluted earnings per average common share were $2.01$1.92 for the nine months ended September 30, 2017 as2018 compared to $1.00 $2.02for the nine months ended September 30, 2016.2017.

183
Table of Contents


Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $598$143 million for the nine months ended September 30, 20172018 as compared to the same period in 2016.2017. The year-over-year increase in Revenue net of purchased power and fuel expense was primarily due to the following favorable factors:
Increase of $96 million at ComEd primarily due to higher electric distribution and transmission formula rate revenues resulting from increased capital investment and higher allowed electric distribution ROE, partially offset by the impact of favorable weather conditions in 2016;
Increase of $83 million at BGE primarily due to the impacts of the electric and natural gas distribution rate increases issued by the MDPSC in June 2016 and July 2016 and an increase in transmission formula rate revenues; and
Increase of $711 million in Revenue net of purchased power and fuel due to the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016, as well as distribution rate increases effective in 2016 and 2017.
The year-over-year increase in Revenue net of purchased power and fuel expense was partially offset by the following unfavorable factors:
Decrease of $180$202 million at Generation primarily due to the conclusion of the Ginna Reliability Support Services Agreement, the impact of declining natural gas prices on Generation's natural gas portfolio, the impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES and Illinois ZES (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017), increased nuclear volumes primarily as a result ofcapacity prices, the acquisition of the FitzPatrick nuclear facility and decreased nuclear outage days, the addition of two combined-cycle gas turbines in Texas and the impacts of Generation's natural gas portfolio, partially offset by lower realized energy prices, the absence of oil inventory write downsEGTP revenues net of purchased power and fuel expense resulting from its deconsolidation in 2017.the fourth quarter of 2017, lower energy efficiency revenues and decreased revenues related to the sale of Generation's electrical contracting business in 2018;
DecreaseIncrease of $62 million at PECO primarily due to unfavorable weather conditions; and
Decrease of $48$57 million at Generation due to lower mark-to-market losseslosses;
Increase of $161$132 million at PECO, DPL and ACE primarily due to favorable weather conditions and volumes within their respective service territories;
Increase of $33 million due to higher mutual assistance revenues across all Utility Registrants, primarily at ComEd;
Decrease of $95 million at ComEd primarily due to lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to FEJA; and
Decrease of $274 million in 2017 comparedelectric and gas revenues across all Utility Registrants, primarily reflecting lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates, partially offset by higher utility revenues due to $113 million in 2016.regulatory rate increases at ComEd, BGE, Pepco, DPL and ACE.
Operating and maintenance expense increaseddecreased by $55$622 million for the nine months ended September 30, 2017 as2018 compared to the same period in 20162017 primarily due to the following unfavorable factors:
IncreaseDecrease of $288$411 million at Generation due to higherlong-lived asset impairment charges;impairments primarily related to the EGTP assets held for sale in 2017;
IncreaseDecrease of $88$163 million at Generation in labor, contracting and materials expense due to decreased spending related to energy efficiency projects and decreased costs related to the sale of Generation's electrical contracting business in 2018.
Decrease of $95 million at ComEd primarily due to the change to defer and recover over time energy efficiency costs pursuant to FEJA;
Decrease of $66 million at Generation due to increased nuclear outagelower merger-related costs;
Increase in Generation's labor, contracting and materials costs of $74 million primarily due to the acquisition of FitzPatrick beginning on March 31, 2017; and
Increase of $253 million at PHI due to the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.
The year-over-year increase in Operating and maintenance expense was partially offset by the following favorable factors:
Decrease of $589 million at Exelon due to merger commitment and other merger-related costs of $63 million in 2017 compared to $652 million in 2016; and
Decrease of $56 million at BGE primarily due to certain disallowances contained in the June and July 2016 rate orders.
Depreciation and amortization expense decreased by $7 million primarilyGeneration due to lower accelerated depreciation and amortization expense asnuclear refueling outage costs;
Decrease of $32 million due to a resultsupplemental NEIL insurance distribution at Generation;

Table of Contents

Increase of $47 million due to higher one-time charges related to Generation's decision to early retire the 2017Oyster Creek nuclear facility in 2018, including a remeasurement to the ARO, compared to one-time charges related to Generation’s decision to early retire the TMI nuclear facility in 2017;
Increase of $33 million due to higher mutual assistance expenses across all Utility Registrants, primarily at ComEd;
Increase of $97 million at PECO and BGE due to increased storm costs; and
Increase of $22 million at Pepco due to a charge associated with a remeasurement of the Buzzard Point ARO.
Depreciation and amortization expense increased by $470 million for the nine months ended September 30, 2018 compared to the previous decisionsame period in 20162017 primarily due to early retire the Clinton and Quad Cities nuclear facilities, partially offset by increased depreciation expense as a result of ongoing capital expenditures across all operating companies, accelerated depreciation and amortization due to Generation's decision to early retire the inclusionOyster Creek and TMI nuclear facilities, increased amortization of PHI's resultsPepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues), partially offset by certain regulatory assets that became fully amortized as of December 31, 2017 for BGE.
Taxes other than income increased due to increased gross receipts tax accruals at PECO and Pepco for the nine months ended September 30, 20172018 compared to the same period March 24, 2016 to September 30, 2016.in 2017.

184
TableGain on sales of Contents


Taxes other than incomeassets and businesses increased by $145$51 million primarily due to increased property taxes as a result of the addition of FitzPatrick, increased gross receipts tax expense and increased sales and use tax expense at Generation, as well as the inclusion of PHI's results for the nine months ended September 30, 20172018 compared to the same period March 24, 2016 to September 30, 2016.
Gain on sales of assets decreased by $37 millionin 2017 primarily due to Generation's gain associated with the sale of the New Boston generating site in 2016.its electrical contracting business.
Bargain purchase gain increaseddecreased by $233 million due to the gain associated with Generation'sthe FitzPatrick acquisition in the first quarter of FitzPatrick in 2017.
Interest expense, net increaseddecreased by $15$56 million due to retirement of long-term debt.
Other, net decreased by $431 million primarily due to additional interest recorded in the second quarter 2017 related to Exelon's like-kind exchange tax position, higher outstanding debt and the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016, partially offset by additional interest recorded in the third quarter 2016 related to Exelon's like-kind exchange tax position.
Other, net increased by $348 million primarily due to higherlower net unrealized and realized gains on NDT funds at Generation for the nine months ended September 30, 2017 as2018 compared to the same period in 2016 and the penalty recorded in 2016 related to Exelon's like-kind exchange tax position.2017.
Exelon’s effective income tax rates for the nine months ended September 30, 2018 and 2017 were 11.6% and 2016 were 23.5% and 39.1%, respectively. The decrease in the effective income tax rate for the nine months ended September 30, 2018 compared to the same period in 2017 is primarily related to tax savings due to the lower federal income tax rate as a result of the TCJA at all Registrants, which is offset in Operating revenues at the Utility Registrants for the anticipated pass back of the tax savings through customer rates. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on TCJA's impact on regulatory proceedings.
For further detailadditional information regarding the financial results for the three and nine months ended September 30, 2017,2018, including explanation of the non-GAAP measure Revenue net of purchased power and fuel expense, see the discussions of Results of Operations by SegmentRegistrant below.
Adjusted (non-GAAP) Operating Earnings   
Exelon’s adjusted (non-GAAP) operating earnings for the three months ended September 30, 20172018 were $821$856 million, or $0.85$0.88 per diluted share, compared with adjusted (non-GAAP) operating earnings

Table of $841Contents

of $820 million, or $0.91$0.85 per diluted share for the same period in 2016.2017. Exelon’s adjusted (non-GAAP) operating earnings for the nine months ended September 30, 20172018 were $1,935$2,467 million, or $2.05$2.55 per diluted share, compared with adjusted (non-GAAP) operating earnings of $2,078$1,943 million, or $2.24$2.06 per diluted share for the same period in 2016.2017. 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 period-over-period 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.

185
Table of Contents


The following tables provide a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2017 as2018 compared to the same period in 2016.2017.
 Three Months Ended September 30,
 2017 2016
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$824
 $0.85
 $490
 $0.53
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $29 and $35, respectively)
(45) (0.05) (54) (0.06)
Unrealized Gains Related to NDT Fund Investments(b) (net of taxes of $45 and $48, respectively)
(67) (0.07) (70) (0.07)
Amortization of Commodity Contract Intangibles(c) (net of taxes of $8 and $8, respectively)
12
 0.01
 13
 0.01
Merger and Integration Costs(d) (net of taxes of $1 and $10, respectively)
(1) —
 13
 0.01
Merger Commitments(e) (net of taxes of $1)
—
 —
 5
 0.01
Long-Lived Asset Impairments(f) (net of taxes of $16 and $5, respectively)
24
 0.03
 11
 0.01
Plant Retirements and Divestitures(g) (net of taxes of $47 and $129, respectively)
71
 0.08
 204
 0.22
Cost Management Program(h) (net of taxes of $8 and $5, respectively)
13
 0.01
 7
 0.01
Like-Kind Exchange Tax Position(i) (net of taxes of $61)
—
 —
 199
 0.21
Asset Retirement Obligation(j) (net of taxes of $1)
(2) —
 —
 —
Bargain Purchase Gain(k) (net of taxes of $0)
(7) (0.01) —
 —
Reassessment of State Deferred Income Taxes(l) (entire amount represents tax expense)
(21) (0.02) —
 —
Noncontrolling Interests(m) (net of taxes of $4 and $5, respectively)
20
 0.02
 23
 0.03
Adjusted (non-GAAP) Operating Earnings$821
 $0.85
 $841
 $0.91
 Three Months Ended September 30,
 2018 2017
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$733
 $0.76
 $823
 $0.85
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $20 and $29, respectively)
(55) (0.06) (45) (0.05)
Unrealized Gains Related to NDT Fund Investments(b) (net of taxes of $4 and $51, respectively)
(53) (0.06) (67) (0.07)
Amortization of Commodity Contract Intangibles(c) (net of taxes of $0 and $8, respectively)
—
 —
 12
 0.01
Merger and Integration Costs(d) (net of taxes of $0 and $1, respectively)
—
 —
 (1) —
Long-Lived Asset Impairments(f) (net of taxes of $2 and $16, respectively)
6
 0.01
 24
 0.03
Plant Retirements and Divestitures(g) (net of taxes of $70 and $47, respectively)
202
 0.21
 71
 0.08
Cost Management Program(h) (net of taxes of $4 and $8, respectively)
13
 0.01
 13
 0.01
Bargain Purchase Gain(i) (net of taxes of $0 and $0, respectively)
—
 —
 (7) (0.01)
Asset Retirement Obligation(n) (net of taxes of $6 and $1, respectively)
16
 0.02
 (2) —
Change in Environmental Liabilities (net of taxes of $3 and $0, respectively)(9) (0.01) —
 —
Reassessment of Deferred Income Taxes(k) (entire amount represents tax expense)
(18) (0.02) (21) (0.02)
Noncontrolling Interests(m) (net of taxes of $4 and $4, respectively)
21
 0.02
 20
 0.02
Adjusted (non-GAAP) Operating Earnings$856
 $0.88
 $820
 $0.85

186
Table of Contents


 Nine Months Ended September 30,
 2017 2016
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$1,899
 $2.01
 $930
 $1.00
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $62 and $46, respectively)
97
 0.10
 67
 0.07
Unrealized Gains Related to NDT Fund Investments(b) (net of taxes of $137 and $89, respectively)
(211) (0.22) (127) (0.13)
Amortization of Commodity Contract Intangibles(c) (net of taxes of $17 and $6, respectively)
27
 0.03
 8
 0.01
Merger and Integration Costs(d) (net of taxes of $24 and $36, respectively)
39
 0.04
 92
 0.10
Merger Commitments(e) (net of taxes of $137 and $114, respectively)
(137) (0.15) 400
 0.43
Long-Lived Asset Impairments(f) (net of taxes of $188 and $67, respectively)
293
 0.31
 104
 0.11
Plant Retirements and Divestitures(g) (net of taxes of $89 and $214, respectively)
137
 0.15
 338
 0.37
Cost Management Program(h) (net of taxes of $15 and $17, respectively)
24
 0.03
 26
 0.03
Like-Kind Exchange Tax Position(i) (net of taxes of $66 and $61, respectively)
(26) (0.03) 199
 0.21
Asset Retirement Obligation(j) (net of taxes of $1)
(2) —
 —
 —
Bargain Purchase Gain(k) (net of taxes of $0)
(233) (0.25) —
 —
Reassessment of State Deferred Income Taxes(l) (entire amount represents tax expense)
(42) (0.04) —
 —
Tax Settlements(n) (net of taxes of $1)
(5) (0.01) —
 —
Noncontrolling Interests(m) (net of taxes of $16 and $8, respectively)
75
 0.08
 41
 0.04
Adjusted (non-GAAP) Operating Earnings$1,935
 $2.05
 $2,078
 $2.24
 Nine Months Ended September 30,
 2018 2017
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$1,858
 $1.92
 $1,907
 $2.02
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $26 and $62, respectively)
74
 0.08
 97
 0.10
Unrealized Losses (Gains) Related to NDT Fund Investments(b) (net of taxes of $118 and $181, respectively)
94
 0.10
 (211) (0.22)
Amortization of Commodity Contract Intangibles(c) (net of taxes of $0 and $17, respectively)
—
 —
 27
 0.03
Merger and Integration Costs(d) (net of taxes of $1 and $24, respectively)
5
 —
 39
 0.04
Merger Commitments(e) (net of taxes of $0 and $137, respectively)
—
 —
 (137) (0.15)
Long-Lived Asset Impairments(f) (net of taxes of $13 and $188, respectively)
36
 0.04
 293
 0.31
Plant Retirements and Divestitures(g) (net of taxes of $148 and $89, respectively)
422
 0.43
 137
 0.15
Cost Management Program(h) (net of taxes of $10 and $15, respectively)
29
 0.03
 24
 0.03
Bargain Purchase Gain(i) (net of taxes of $0 and $0, respectively)
—
 —
 (233) (0.25)
Asset Retirement Obligation(n) (net of taxes of $6 and $1, respectively)
16
 0.02
 (2) —
Change in Environmental Liabilities (net of taxes of $1 and $0, respectively)(4) —
 —
 —
Like-Kind Exchange Tax Position(j) (net of taxes of $0 and $66, respectively)
—
 —
 (26) (0.03)
Reassessment of Deferred Income Taxes(k) (entire amount represents tax expense)
(27) (0.03) (42) (0.04)
Tax Settlements(l) (net of taxes of $0 and $1, respectively)
—
 —
 (5) (0.01)
Noncontrolling Interests(m) (net of taxes of $9 and $16, respectively)
(36) (0.04) 75
 0.08
Adjusted (non-GAAP) Operating Earnings$2,467
 $2.55
 $1,943
 $2.06
_________
Note:
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2018 and 2017 ranged from 26.0 percent to 29.0 percent and 39.0 percent to 41.0 percent.percent, respectively. Under IRS regulations, NDT fund investment returns are taxed at differingdifferent rates for investments if they are in qualified vs.or non-qualified funds. The effective tax rates applied tofor the unrealized gains and losses related to NDT Fundfund investments were 7.7 percent and 43.2 percent for the three months ended September 30, 2018 and 2017, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 55.5 percent and 46.2 percent for the three and nine months ended September 30, 2018 and 2017, respectively, and 52.6 percent and 52.5 percent for the three and nine months ended September 30, 2016, respectively.

(a)ReflectsPrimarily reflects the impact of net gains and losses on Generation’s economic hedging activities. See Note 10 - 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 net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. See Note 13 - Nuclear DecommissioningThe impacts of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.

Table of Contents

(c)Reflects the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions in 2017, and in 2016, the Integrys and ConEdison Solutions acquisitions.
(d)Reflects certain
Primarily reflects certain costs incurred for the PHI acquisition in 2017associated with mergers and 2016acquisitions, including, if and Generation's FitzPatrick acquisition in 2017, includingwhen applicable, professional fees, employee-related expenses and integration activities. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detailIn 2017, reflects costs related to mergerthe PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs. In 2018, reflects costs related to the PHI acquisition.
(e)RepresentsPrimarily reflects a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions in 2017, and costs and adjustments incurred as part of the settlement orders approving the PHI acquisition in 2017 and 2016. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to PHI Merger commitments.acquisitions.
(f)Primarily reflects impairments as a resultcharges to earnings related to the impairment of the ExGenTexas Power, LLCEGTP assets held for sale in 2017, and impairmentsin 2018 the impairment of Upstream assets and certain wind projects at Generation in 2016.Generation.
(g)Primarily reflects accelerated depreciation and amortization expenses increases to materials and supplies inventory reserves,one-time charges for severance reserves and construction work in progress impairments associated with Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, partially offset in 2016 by a gain associated with Generation's sale of the New Boston generating site and Generation's decision to early retire the Three Mile Island nuclear facility in 2017. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO and accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the Three Mile Island nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business.
(h)ReflectsPrimarily represents severance and reorganization costs related to a cost management program.

187
Table of Contents


(i)Represents adjustments to income tax, penalties and interest expenses in 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position, and in 2016, the recognition of a penalty and associated interest expense in 2016 as a result of a tax court decision on Exelon’s like-kind exchange tax position.
(j)Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the nonregulatory units.
(k)Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.
(l)(j)Reflects adjustments to income tax, penalties and interest expenses in the non-cash impactsecond quarter of the remeasurement of state deferred income taxes, primarily2017 as a result of changes in forecasted apportionmentthe finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.
(k)Reflects the PHI acquisition in 2016, and in 2017, changes in the Illinois and District of Columbia statutory tax ratesrate and changes in forecasted apportionment in 2017. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the Tax Cuts and Jobs Act (TCJA) and changes in forecasted apportionment.
(l)Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI’s unregulated business interests.
(m)RepresentsReflects elimination from Generation’s results of the noncontrolling interestinterests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.
(n)Reflects benefitsa non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the favorable settlementnon-regulatory units in 2017 of certain income tax positions2017. In 2018, reflects an increase at Pepco related primarily to PHI's unregulated business interests that were transferred to Generation.asbestos identified at its Buzzard Point property.
Merger, Integration
Significant 2018 Transactions and Acquisition CostsDevelopments
As a resultRegulatory Implications of the PHI Merger that was completed on March 23, 2016, theTax Cuts and Jobs Act (TCJA)
The Utility Registrants have incurred costs associatedmade filings with evaluating, structuringtheir respective State regulators to begin passing back to customers the ongoing annual tax savings resulting from the TCJA. The amounts being proposed to be passed back to customers reflect the annual benefit of lower income tax rates and 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 partsettlement of a portion of deferred income tax regulatory liabilities established upon enactment of the merger approval process, and integrating the former PHI businesses into Exelon. In addition, as a resultTCJA. The Utility Registrants have identified over $675 million in ongoing annual savings to be returned to customers related to TCJA from their distribution utility operations. See Note 6 — Regulatory Matters of the acquisitionCombined Notes to Consolidated Financial Statements for additional information.
Early Plant Retirements
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in 2018. On September 17, 2018, Oyster Creek permanently ceased generation operations. Because of the FitzPatrick nuclear generating station on March 31, 2017,decision to early retire Oyster Creek in 2018, Exelon and Generation incurredrecognized certain one-time charges in the first quarter of 2018 related to a materials and supplies inventory reserve adjustment, employee-related costs associatedand construction work-in-progress impairments, among other items.
On July 31, 2018, Generation entered into an agreement with evaluating, structuring,Holtec International and executing the transaction and integrating FitzPatrick into Exelon.
For the three and nine months ended September 30, 2017 and 2016, expense has been recognizedits indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the PHI Mergersale and Generation's FitzPatrick acquisition as follows:
  Pre-tax Expense
  Three Months Ended September 30, 2017
Merger, Integration and Acquisition Costs: 
Exelon(a)
 
Generation(a)
 ComEd PECO BGE 
PHI(a)(b)
 
Pepco(a)(c)
 
DPL(a)
 
ACE(a)(d)
Transaction(e)
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other(f)
 (3) 11
 —
 1
 1
 (15) (8) 1
 (8)
Total $(3) $11
 $—
 $1
 $1
 $(15) $(8) $1
 $(8)
  Pre-tax Expense
  Three Months Ended September 30, 2016
Merger, Integration and Acquisition Costs: 
Exelon(a)
 
Generation(a)
 ComEd PECO BGE 
PHI(a)
 
Pepco(a)
 
DPL(a)
 
ACE(a)
Transaction(e)
 $1
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Employee-Related(g)
 1
 —
 —
 —
 —
 1
 —
 —
 —
Other(f)
 21
 11
 —
 2
 2
 7
 3
 2
 2
Total $23
 $11
 $—
 $2
 $2
 $8
 $3
 $2
 $2
  Pre-tax Expense
  Nine Months Ended September 30, 2017
Merger, Integration and Acquisition Costs: 
Exelon(a)
 
Generation(a)
 ComEd PECO BGE 
PHI(a)(b)
 
Pepco(a)(c)
 
DPL(a)(h)
 
ACE(a)(d)
Transaction(e)
 $5
 $4
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Other(f)
 57
 67
 1
 3
 3
 (17) (6) (6) (6)
Total $62
 $71
 $1
 $3
 $3
 $(17) $(6) $(6) $(6)

188
Tabledecommissioning of Contents


  Pre-tax Expense
  Nine Months Ended September 30, 2016
Merger, Integration and Acquisition Costs: 
Exelon(a)
 
Generation(a)
 
ComEd(i)
 PECO 
BGE(j)
 
PHI(a)(b)
 
Pepco(a)(c)
 
DPL(a)(h)
 
ACE(a)
Transaction(e)
 $36
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Employee-Related(g)
 74
 10
 1
 1
 1
 61
 29
 17
 14
Other(f)
 16
 21
 (8) 3
 (3) 2
 (3) 1
 3
Total $126
 $31

$(7)
$4

$(2) $63
 $26
 $18
 $17
_________
(a)For Exelon, Generation, PHI, Pepco, DPL, and ACE, includes the operations of the acquired businesses beginning on March 24, 2016.
(b)For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $16 million and $24 million, respectively, incurred at PHI that have been deferred and recorded as a regulatory asset for anticipated recovery. For the Successor period March 24, 2016 to September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $13 million incurred at PHI that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.
(c)For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at Pepco that have been deferred and recorded as a regulatory asset for anticipated recovery. For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $10 million incurred at Pepco that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.
(d)For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at ACE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.
(e)External, third party costs paid to advisors, consultants, lawyers and other experts to integrate PHI processes and systems into Exelon, to assist in the due diligence and regulatory approval processes and in the closing of transactions.
(f)Costs to integrate PHI processes and systems into Exelon. For the three and nine months ended September 30, 2017, also includes costs to integrate FitzPatrick processes and systems into Exelon.
(g)Costs primarily for employee severance, pension and OPEB expense and retention bonuses.
(h)For the nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $3 million incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.
(i)For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, incurred at ComEd that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.
(j)For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $6 million incurred at BGE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.
AsOyster Creek. See Note 4 — Mergers, Acquisitions and Dispositions of September 30, 2017, Exelon expectsthe Combined Notes 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 September 30, 2017, Exelon and PHI have incurred approximately $675 million.
Significant 2017 Transactions and Developments
Early Retirement of Three Mile Island FacilityConsolidated Financial Statements for additional information.
On May 30, 2017, Generation announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year and will not receive capacity revenue for that period, the third consecutive year that TMI failed to clear the PJM base residual capacity auction. The plant is currently committed to operate through May 2019. In 2017, as
As a result of the early nuclear plant retirement decision ofdecisions at Oyster Creek and TMI, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $76 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, there will be ongoingalso recognize annual incremental non-cash charges to earnings stemming from

Table of Contents

shortening the expected economic useful life of TMIlives primarily related to accelerated depreciation of plant assets (including any asset retirement costs (ARC))ARC), accelerated amortization of nuclear fuel, and additional asset retirement obligation (ARO)ARO accretion expense associated with the changes in decommissioning timing and cost assumptions. During the three and nine months ended September 30, 2017, both Exelon’s and Generation’s results include an incremental $112 million and $149 million, respectively, of pre-tax expense for these items.

189
Table of Contents


assumptions were also recorded. The following table summarizes the actual incremental non-cash expense item incurred in 2018 and the estimated annual amount and timing of expected incremental non-cash expense items through 2019.expected to be incurred in 2018 and 2019 due to the early retirement decisions.
 September 30, 2017 
Projected(a)
Actual 
Projected(a)
Income statement expense (pre-tax) 2017 2018 2019Nine Months Ended September 30, 2018 2018 2019
Depreciation and Amortization        
Depreciation and amortization(b)
     
Accelerated depreciation(b)(c)
 $141
 $250
 $430
 $325
$441
 $550
 $330
Accelerated nuclear fuel amortization 8
 10
 20
 5
52
 55
 5
Operating and maintenance(d)
32
 35
 5
Total $149
 $260
 $450
 $330
$525
 $640
 $340
_________
(a)Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.
(b)Reflects incremental accelerated depreciation and amortization for TMI and Oyster Creek for the nine months ended September 30, 2018. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018.
(c)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(d)Primarily includes materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments.
EGTP Consent AgreementIn 2017, PSEG also made public financial challenges facing its New Jersey nuclear plants including Salem, of which Generation owns a 42.59% ownership interest. Although Salem is committed to operate through May 2021, the plant faces continued economic challenges and PSEG, as the operator of the plant, is exploring all options.
In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. EGTP’s operating cash flows have been negatively impacted by certain market conditions and the seasonality of its cash flows.  On May 2, 2017, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP, including the revolving credit facility. As a result, in the second quarter 2017, Exelon and Generation classified certain EGTP assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values less costs to sell and included in the other current assets and other current liabilities balances on Exelon's and Generation's Consolidated Balance Sheets. For the three and nine months ended September 30, 2017, a $40 million and $458 million pre-tax impairment loss was recorded within Operating and maintenance expense on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 4 - Mergers, Acquisitions and Dispositions, Note 6 - Impairment of Long-Lived Assets and Note 11 - Debt and Credit Agreements for more information for additional information regarding EGTP and the associated nonrecourse debt.
Acquisition of James A. FitzPatrick Nuclear Generating Station
On March 31, 2017, Generation acquired the 838 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station for a total purchase price of $289 million. In accounting for the acquisition as a business combination, Exelon and Generation recorded an after-tax bargain purchase gain of $233 million which is included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information regarding the Generation's acquisition of FitzPatrick and related costs.
Illinois Future Energy Jobs Act
On December 7, 2016, FEJA was signed into law by23, 2018, the Governor of Illinois. FEJA wasNew Jersey signed new legislation, which became effective June 1, 2017, and includes, among other provisions, (1)immediately, that will establish a Zero Emission Standard (ZES)ZEC program providing compensation for nuclear plants that demonstrate to the NJBPU that they meet certain nuclear-powered generating facilities, (2) an extension ofrequirements, including that they make a significant contribution to air quality in the state and certain adjustmentsthat their revenues are insufficient to ComEd’scover their costs and risks. Under the new legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution formula rate, (3) new cumulative persisting annual energy efficiency MWh savings goalsutilities in New Jersey, including ACE, will be required to purchase those ZECs. The NJBPU has 180 days from the effective date to establish procedures for ComEd, (4) revisionsimplementation of the ZEC program and 330 days from the effective date to determine which nuclear power plants are selected to receive ZECs under the Illinois RPS requirements, (5) provisionsprogram. Assuming the successful implementation of the New Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk of earlier retirement for 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 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.Salem. See Note 5 -6 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA. Seeand Note 78 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information regardingon the economic challenges facing Generation's Clinton and Quad Cities nuclear plantsnew legislation and the expected benefitsNew Jersey ZEC program.
On March 29, 2018, based on ISO-NE capacity auction results for the 2021 - 2022 planning year in which Mystic Unit 9 did not clear, Generation announced it had formally notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets on June 1, 2022 absent any interim and long-term solutions for reliability and regional fuel security. The ISO-NE announced that it would take a three-step approach to fuel security. First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel security for the ZES.2022 - 2024 planning years.  Second, ISO-NE planned to file tariff revisions to allow it to retain other resources for fuel security in the capacity market if necessary in the future. Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot

190
Table of Contents


Dismissalrecover future operating costs including the cost of Litigation Challenging ZEC Programsprocuring fuel. As a result of these developments, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group during the first quarter of 2018 and no impairment charge was required.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024.
On July 14,2, 2018, FERC issued an order denying ISO-NE's May 1, 2018, waiver request on procedural grounds but accepting ISO-NE's conclusions that retirement of Mystic Units 8 and 9 could cause a violation of mandatory reliability standards as soon as 2022. Accordingly, FERC ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address demonstrated fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. FERC also extended the deadline by which Generation must make a retirement decision for Mystic Units 8 and 9 to January 4, 2019. On August 31, 2018, ISO-NE filed a compliance filing in response to FERC's July 2, 2018 order proposing short-term tariff changes to permit it to retain a resource for fuel security reliability reasons. A number of parties, including Generation, have submitted comments on the proposal, which is pending before FERC.
On July 13, 2018, FERC issued an order accepting the cost-of-service agreement for filing, making findings on certain issues and establishing hearing procedures on an expedited schedule. Further developments such as the failure of ISO-NE to adopt interim and long-term solutions for reliability and fuel security could potentially result in future impairments of the New England asset group, which could be material. See Note 7 — Impairment of Long-Lived Assets and Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Illinois ZEC Procurement
Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue. Winning bidders are entitled to compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. During the three months ended September 30, 2018, Generation recognized revenue of $61 million. During the nine months ended September 30, 2018, Generation recognized revenue of $315 million, of which $150 million related to ZECs generated from June 1, 2017 through December 31, 2017.
Westinghouse Electric Company LLC Bankruptcy
On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. District Court for the Northern District of Illinois dismissed two lawsuits challenging the ZEC program contained in FEJA. On July 17, 2017, the plaintiffs appealed the court’s decisions to the U.S. Court of Appeals for the Seventh Circuit. Plaintiffs-Appellants initial brief was filed on August 28, 2017 and the state’s and Exelon’s briefs were filed on October 27, 2017. Reply briefs are due on December 12, 2017.
Additionally, on July 25, 2017, the U.S. DistrictBankruptcy Court for the Southern District of New York dismissedYork. On January 4, 2018, Westinghouse announced its agreement to be purchased by an affiliate of Brookfield Business Partners, LLC (Brookfield) for approximately $4.6 billion. On March 28, 2018, the Bankruptcy Court entered an Order confirming the Debtor's Second Amended Joint Plan of Reorganization which provides for the transaction with Brookfield. The transaction closed on August 1, 2018. Exelon had contracts with Westinghouse primarily related to Generation's purchase of nuclear fuel, as well as a lawsuit challenging the ZEC program contained in the New York CES. On August 24, 2017, the plaintiffs appealed the decision to the Second Circuit. Plaintiffs-Appellants’ initial brief was filed on October 13variety of services and the state’s and Exelon’s briefs are due on November 17, 2017. Reply briefs are due on December 1, 2017.
These court decisions uphold the ZEC programs which support Illinois’s and New York’s efforts to advance clean energy and preserve affordable and reliable energy resources for customers.  See Note 5 - Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA and the New York CES.
Merger Commitment Unrecognized Tax Benefits
Exelon established a liability for an uncertain tax positionequipment purchases associated with the tax deductibilityoperation and maintenance of certain merger commitments incurred by Exelon in connectionnuclear generating stations. In conjunction with the acquisitionsconfirmation hearing, Exelon had filed a reservation of Constellation in 2012rights regarding reorganizing Westinghouse's assumption of all Exelon contracts. Exelon reached an agreement with Brookfield, and PHI in 2016. Inall Exelon contracts were assumed by Brookfield on the first quarter 2017, as a partclosing date.

Table of its examination of Exelon’s return, the IRS National Office issued guidance concurring with Exelon’s position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million, and $22 million, respectively, as of September 30, 2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.Contents
Combined-Cycle Gas Turbine Projects
In June 2017, Generation commenced commercial operations of two new combined-cycle gas turbines (CCGTs) at the Colorado Bend and Wolf Hollow Generating Stations in Texas. The two new CCGTs have added nearly 2,200 MWs of capacity to Generation’s fleet, enhancing Generation’s strategy to match generation to customer load.  Generation invested approximately $1.5 billion over the past three years to complete the new plant construction, which utilizes new General Electric technology to make them among the cleanest, most efficient CCGTs in the nation.
Utility Rates and Base Rate Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position.

191
Table of Contents


The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2017.2018. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
Company Jurisdiction 
Approved Revenue Requirement Increase
(in millions)
 Approved Return on Equity Completion Date Rate Effective Date
Registrant Jurisdiction 
Approved Revenue Requirement Increase (Decrease)
(in millions)
 Approved Return on Equity Completion Date Rate Effective Date
Pepco District of Columbia (Electric) $(24) 9.525% August 9, 2018 August 13, 2018
Pepco Maryland (Electric) $(15) 9.5% May 31, 2018 June 1, 2018
DPL Maryland (Electric) $38
 9.6% February 15, 2017 February 15, 2017 Delaware (Electric) $(7) 9.7% August 21, 2018 March 17, 2018
DPL Delaware (Electric) $31.5
 9.7% May 23, 2017 June 1, 2017 Maryland (Electric) $13
 9.5% February 9, 2018 September 5, 2018
DPL Delaware (Natural Gas) $4.9
 9.7% June 6, 2017 July 1, 2017
Pepco District of Columbia (Electric) $37
 9.5% July 25, 2017 August 15, 2017
ACE New Jersey (Electric) $43
 9.6% September 22, 2017 October 1, 2017
Pepco Maryland (Electric) $32
 9.5% October 27, 2017 October 20, 2017
Pending Distribution Base Rate Case Proceedings
Company Jurisdiction 
Requested Revenue Requirement Increase
(in millions)
 Requested Return on Equity Filing Date Expected Completion Timing
Registrant Jurisdiction 
Requested or Settlement Revenue Requirement Increase (Decrease)
(in millions)
 Requested or Settlement Return on Equity Filing or Settlement Date Expected Completion Timing
ComEd 
Illinois (Electric)(a)
 $96
(b) 
8.4%
(c) 
April 13, 2017 Fourth quarter 2017 Illinois (Electric) $(23) 8.69% April 16, 2018 Fourth quarter 2018
PECO Pennsylvania (Electric) $25
 
N/A(a)

 August 28, 2018 Fourth quarter 2018
BGE Maryland (Natural Gas) $61
 10.50% June 8, 2018 (Updated on August 24, 2018 and October 12, 2018) First quarter 2019
DPL Maryland (Electric) $22
 10.1% July 14, 2017 (Updated on September 28, 2017) First quarter 2018 Delaware (Natural Gas) $(4) 9.70% September 7, 2018 (Updated on October 2, 2018) Fourth quarter 2018
DPL Delaware (Electric) $31
 10.1% August 17, 2017 (Updated on October 18, 2017) Third quarter 2018
DPL Delaware (Natural Gas) $13
 10.1% August 17, 2017 Third quarter 2018
ACE New Jersey (Electric) $109
 10.10% August 21, 2018 Third quarter 2019
__________________
(a)Pursuant to EIMA, ComEd’s electric distribution rates are established through a performance-based formula through which ComEd is required to file an annual update on or before May 1, with resulting rates effectiveNo overall ROE was specified in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred for the year (annual reconciliation).
(b)Reflects an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation.
(c)ComEd’s allowed ROE under its electric distribution formula rate is the annual average rate on 30-year treasury notes plus 580 basis points and is subject to reduction if ComEd does not deliver certain reliability and customer service benefits. The initial revenue requirement for 2017 reflects an allowed ROE of 8.40%, while the annual reconciliation reflects an allowed ROE of 8.34%, which is inclusive of a 6 basis point performance penalty.partial settlement agreement.

See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these base rate case proceedings.
192
Table of Contents


Transmission Formula RatesRate
The following total increases/(decreases)/increases were included in ComEd’s, BGE’s,ComEd's, BGE's, Pepco's, DPL's and ACE's 20172018 annual electric transmission formula rate filings:updates.
 2017
Annual Transmission Filings(a)
ComEd BGE Pepco DPL ACE
Initial revenue requirement
    increase
$44
 $31
 $5
 $6
 $20
Annual reconciliation (decrease) increase(33) 3
 15
 8
 22
Dedicated facilities decrease(b)
—
 (8) —
 —
 —
Total revenue requirement increase$11
 $26
 $20
 $14
 $42
          
Allowed return on rate base(c)
8.43% 7.47% 7.92% 7.16% 8.02%
Allowed ROE(d)
11.50% 10.50% 10.50% 10.50% 10.50%
 2018
Annual Transmission Updates(a)(b)
ComEd BGE Pepco DPL ACE
Initial revenue requirement (decrease) increase$(44) $10
 $6
 $14
 $4
Annual reconciliation increase (decrease)18
 4
 2
 13
 (4)
Dedicated facilities increase(c)
—
 12
 —
 —
 —
Total revenue requirement (decrease) increase$(26) $26
 $8
 $27
 $—
          
Allowed return on rate base(d)
8.32% 7.61% 7.82% 7.29% 8.02%
Allowed ROE(e)
11.50% 10.50% 10.50% 10.50% 10.50%
_________
(a)All rates are effective June 2017,2018, subject to review by the FERC and other parties, which is due by fourth quarter 2017.2018.
(b)The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA.  See further discussion above. 
(c)BGE's transmission revenues include a FERC approvedFERC-approved dedicated facilities charge to recover the costs of providing transmission service to a specifically designated load by BGE.
(c)(d)Represents the weighted average debt and equity return on transmission rate bases.
(d)(e)As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization.
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate wouldwill be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the final outcome of the settlement or hearing proceedings,this proceeding, or the transmission formula FERC may approve.
See Note 5 - Regulatory MattersOn May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a revenue decrease of $6 million. The revenue decrease of $6 million included an approximately $20 million reduction as a result of the Combined Notestax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to Consolidated Financial Statements for further details on these regulatory proceedings.
Westinghouse Electric Company LLC Bankruptcy
On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. In the petitions and supporting documents, Westinghouse makes clear that its requests for relief center on one business area that is losing money — the construction of nuclear power plants in Georgia and South Carolina. Through the bankruptcy, Westinghouse seeks to reorganize around its profitable core business, which includes nuclear fuel fabrication and related services and other services provided to existing nuclear power plants in the U.S. and around the world. For these reasons, at this time, Generation does not anticipate disruption to the Westinghouse fuel fabrication contracts for Braidwood, Byron, or Ginna or other existing contracts for Generation's nuclear power plants. Generation is monitoring the bankruptcy proceeding to ensure that its rights are protected.
ExGen Renewables Holdings, LLC Transaction
On July 6, 2017, ExGen Renewables Holdings, LLC, a wholly owned subsidiary of Generation, completed the sale of a 49% interest of ExGen Renewables Partners, LLC, a newly formed owner and operator of approximately 1,296 megawatts of Generation's operating wind and solar electric generating facilities. ExGen Renewables Holdings will be the managing member of ExGen Renewables Partners, LLC, and have day-to-day control and managementrefund.

193
Table of Contents


over its renewable generation portfolio. The closingWinter Storm-Related Costs
During March 2018 there were powerful nor'easter storms that brought a mix of heavy snow, ice and high sustained winds and gusts to the transaction was subjectregion that interrupted electric service delivery to certain regulatory approvals, includingcustomers in PECO's, BGE's, Pepco's, DPL's and ACE's service territories. Restoration efforts included significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies, which resulted in incremental operating and maintenance expense and incremental capital expenditures in the Federal Energy Regulatory Commission (FERC) and the Public Utility Commission of Texas (PUCT) which were received during the secondfirst quarter of 2017.2018 for PECO, BGE, PHI, Pepco, DPL and ACE. In addition, PHI, Pepco, DPL and ACE recorded regulatory assets for amounts that are probable of recovery through customer rates. The sale price was $400 million plus immaterial working capital and other customary post-closing adjustments. The net proceeds, after approximately $100 million of income taxes, will be used to pay down debt and for general corporate purposes. Generation will continue to consolidate ExGen Renewables Partners, LLC and will record a noncontrolling interest on its Consolidated Balance Sheetimpacts recorded by the Registrants for the investor's initial equity share as well as earnings attributable to the noncontrolling interest in the Consolidated Statements of Operations and Comprehensive Income each period going forward.nine months ended September 30, 2018 are presented below:
Hurricanes Harvey, Irma and Maria Impacts
Although Exelon subsidiaries provided substantial assistance to recovery efforts following Hurricanes Harvey and Irma, Hurricanes Harvey, Irma and Maria are not expected to have a material impact on the Registrants’ businesses or financial results given the limited operations in the areas affected by the storms.
   (in millions)
 Customer Outages Incremental Operating & Maintenance Incremental Capital Expenditures
Exelon1,727,000
 $88
(b) 
$89
PECO750,000
 53
 35
BGE425,000
 31
 15
PHI(a)
552,000
 4
(b) 
39
Pepco182,000
 2
(b) 
4
DPL138,000
 2
(b) 
4
ACE232,000
 —
(b) 
31
________
(a)PHI reflects the consolidated customer outages, incremental operating & maintenance and incremental capital expenditures of Pepco, DPL and ACE.
(b)Excludes amounts that were deferred and recognized as regulatory assets at Exelon, PHI, Pepco, DPL and ACE of $28 million, $28 million, $7 million, $1 million and $20 million, respectively.
Exelon’s Strategy and Outlook for 20172018 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 utilitiesThe Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and 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 utilitiesUtility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Exelon utilitiesUtility Registrants make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart meter

Table of Contents

technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon's Board of Directors has approved a dividend policy providing a raise of 2.5%5% each year for three years,the period covering 2018 through 2020, beginning with the June 2016March 2018 dividend.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions

194
Table of Contents


to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS of the Exelon 20162017 Form 10-K for additional information regarding market and financial factors.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy.  In August 2015, Exelon announced a cost management program initiated latefocused on cost savings of approximately $400 million at BSC and Generation, which was fully realized in 2015,2018.  Approximately 75% of the company committedsavings were related to reducing operation and maintenance expenses and capital costs by approximately $350Generation, with the remaining amount related to the Utility Registrants. In November 2017, Exelon announced a commitment for an additional $250 million and $50 million, respectively, of which approximately 35% of run-ratecost savings, was achieved by the end of 2016.  Approximately 60% of run-rate savings are expectedprimarily at Generation, to be achieved by 2020. In November 2018, Exelon announced the endelimination of 2017an approximately additional $200 million of annual ongoing costs, through initiatives primarily at Generation and fully realized in 2018. At least 75% of the savings areBSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants.
In November 2017, Exelon announced These actions are in response to the elimination of approximately $250 million of annual ongoing costs, primarily at Generation, by 2020.  This announcement is a resultcontinuing economic challenges confronting all parts of Exelon’s continuousbusiness and industry, necessitating continued focus on improving its cost profilemanagement through enhanced efficiency and productivity.  These cost reductions result in a cost profile that better aligns with current market conditions.  The targeted cost savings are incremental to the expected savings from previous cost management initiatives. 
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 BusinessesBusinesses.. 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$28 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$11 billion by the end of 2021.2022. 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.

Table of Contents

See Note 5—3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements Exelon 2017 Form 10-K for additional information on the Smart Meter and Smart Grid Initiatives and infrastructure development and enhancement programs.
Competitive Energy BusinessesBusinesses..Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development. As of September 30, 2017, Generation has currently approved plans to invest a total of approximately $300 million through 2018 to complete new plant construction currently in progress.
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 Corporate, 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 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion. See Liquidity and Capital Resources - Credit Matters - Exelon Credit Facilities below.
For further detailadditional information regarding the Registrants' liquidity for the nine months ended September 30, 2017,2018, see Liquidity and Capital Resources discussion below.

195
Table of Contents


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 debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. See Note 6 Impairment of Long-Lived Assets and Note 11 -— Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for additional information on nonrecourse debt.

Table of Contents

Other Key Business Drivers and Management Strategies
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,FERC Inquiry on December 12, 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. On June 20, 2017, the DC Circuit denied all the appeals.
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.

196
Table of Contents


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, 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, 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. 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 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. 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 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on the impacts of the MISO announcement.
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.

197
Table of Contents


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 between the utility and its merchant generation affiliate for what was collectively more than 6,000 MW 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 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. The EPSA parties have filed motion to expedite both proceedings. 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, for Generation's facilities in NYISO and PJM expected to receive ZEC compensation (Quad Cities, Ginna, Nine Mile Point and FitzPatrick), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in those auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any such mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. On August 30, 2017, EPSA filed motions to lodge the district court decisions dismissing the complaints and urging FERC to act expeditiously on its requests to expand the MOPR. On September 14, 2017, Exelon filed a response in each docket noting that it does not oppose the motions to lodge but arguing that the requests to expedite a decision on the requests to expand the MOPR have no merit. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.
DOE Notice of Proposed RulemakingResiliency
On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On October 2, 2017, theJanuary 8, 2018, FERC issued a notice inviting comments regardingan order terminating the rulemaking docket that it initiated to address the proposed rule in the DOE NOPR, within 21 daysconcluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and establishedthat it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, FERC initiated a new docket whereinproceeding to consider resiliency challenges to the FERC will consider the matter. On October 23, 2017, Exelon filed comments with the FERC, supporting the goals of the NOPRbulk power system and urging the agency to take swiftevaluate whether additional FERC action to protect customers from power supply interruptions

198
Table of Contents


address resiliency would be appropriate. FERC directed each RTO and ensure resiliencyISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Thereafter, interested parties submitted reply comments on May 9, 2018, and a few parties submitted further replies. Exelon has been and will continue to be an active participant in a way that appropriately balances the value and cost to customers.  Exelonthese proceedings but cannot predict the final outcome of the proceeding or its potential financial impact, if any, on Exelon or Generation.
Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs
PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new gas-fired resources.
On January 9, 2017, EPSA filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. A similar complaint also against PJM was filed at FERC on May 31, 2018. These complaints generally allege that the relevant MOPR should be expanded to also apply to existing resources including those receiving ZEC compensation under the New York CES and Illinois ZES programs. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS programs that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation (Quad Cities, Ginna, Fitzpatrick and Nine Mile Point), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in future capacity auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any mitigation of these generating resources could have a material effect on Exelon’s

Table of Contents

and Generation’s future cash flows and results of operations. The same risk would also exist for the Salem facility if Salem is selected as an eligible facility under the NJ ZEC program.
Separately, PJM submitted two proposed alternative capacity market reforms in April 2018 for FERC’s consideration. PJM argued that either alternative will resolve any conflict between state policy support for certain resources and the need to ensure reasonable prices for non-supported resources. The first alternative was to implement a twice-run capacity clearing mechanism (known as the repricing proposal) and, if not acceptable to FERC, a second alternative that would expand the existing MOPR to both new and existing generating resources, subject to certain exemptions (known as MOPREx).
In June 2018, FERC issued an order rejecting both of PJM’s proposed alternatives, finding both to be unjust and unreasonable. In the same order, FERC also addressed one of the MOPR complaints involving PJM and concluded based on that complaint and PJM’s filing that PJM’s existing tariff allows resources receiving out-of-market support to affect capacity prices in a manner that will cause unjust and unreasonable and unduly discriminatory rates in PJM regardless of the intent motivating the support. FERC suggested that modifying two elements of PJM’s existing tariff could produce a just and reasonable replacement and asked for initial comments on its proposal by August 28, 2018, later extended to October 2, 2018. First, FERC found that an expansion of the current MOPR mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or REC compensation, could protect the capacity markets from unwanted price suppression. Second, FERC preliminarily found that a modified version of PJM’s existing Fixed Resource Requirement (FRR) option could enable state subsidized resources and a corresponding amount of load to be removed from the capacity market, thereby alleviating their price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through mechanisms other than through PJM’s existing market mechanism. FERC established March 21, 2016 as the refund effective date and also allowed PJM to delay its next capacity auction from May 2019 to August 2019 to allow parties time to develop and file proposals in the FERC proceeding, FERC time to determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates, environmental organizations and other nuclear generators, submitted shared principles supporting a workable new FRR mechanism (as suggested by FERC) and detailing how such a mechanism should be implemented. Exelon also submitted individual comments covering matters not addressed in the shared principles. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. It is too early to predict the final outcome of each of these proceedings or their potential financial impact, if any, on Exelon or Generation.
Section 232 Uranium Petition
On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce (DOC) seeking relief under Section 232 of the Trade Expansion Act of 1962 (as amended) from imports of uranium products, alleging that these imports threaten national security (the Petition). The Trade Expansion Act of 1962 (the Act) was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.
On July 18, 2018, the Secretary announced that the DOC has initiated an investigation in response to the petition. The Secretary has 270 days to prepare and submit a report to President Trump, who then has 90 days to act on the Secretary's recommendations. Exelon and Generation cannot currently predict the outcome of this investigation. The relief sought by the petitioners would require U.S. nuclear reactors

Table of Contents

to purchase at least 25% of their uranium needs from domestic mines over the next 10 years, although the DOC will make an independent determination regarding an appropriate remedy should it find that imports impair national security. It is reasonably possible that if this petition is successful the resulting increase in nuclear fuel costs in future periods could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.
Potential DOE Order Pursuant to Defense Production Act and Federal Power Act
The DOE is considering an Order directing ISOs, for 24 months, to purchase electric energy or generation capacity from a designated list of coal and nuclear generation facilities. Based on a draft memorandum, the Order would be pursuant to DOE's authorities under the Defense Production Act and Federal Power Act, and would forestall any further actions towards retiring, decommissioning, or deactivating coal and nuclear facilities during the term of the Order. The Order would emphasize the importance of grid resiliency, in addition to grid reliability, noting that fuel security and diversity are critical components of resiliency. The DOE recognizes that the underlying economic and regulatory issues are complex and will take time resolve. The Order's 24-month duration would enable DOE to conduct additional analyses to gain a detailed understanding of location-specific vulnerabilities in U.S. energy delivery systems, while preserving certain generation facilities. Exelon has been and will continue to be an active participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
Energy Demand
Modest economic growth partially offset by energy efficiency initiatives is resulting in relatively flat to declining load growth in electricity for the utilities. There is a decrease in projected load for electricity for ComEd, PECO, BGE, and ACE, and an essentially flat projected load for electricity for DPL.Utility Registrants. ComEd, PECO, BGE, Pepco, DPL and ACE are projecting load volumes to decreaseincrease by (1.2)%0.5%, (0.4)%1.7%, (2.9)%0.7%, (2.3)%0.2%, (0.4)%,1.3% and (3.5)%4.3% respectively, in 20172018 compared to 2016.2017.
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, forwardForward 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 20172018 dividends of $0.3275$0.345 per share on Exelon's common stock. The first quarter 20172018 dividend was paid on March 10, 2017.9, 2018. The dividend increased from the fourth quarter 20162017 amount to reflect the Board's decision to raise Exelon's dividend 2.5%5% each year for the next three years,period covering 2018 through 2020, beginning with the June 2016March 2018 dividend.
Exelon's Boardboard of Directorsdirectors declared the second quarter 20172018 dividends of $0.3275$0.345 per share each on Exelon's common stock. The second quarter 2017 dividendstock and was paid on June 9, 2017.8, 2018.
Exelon's Boardboard of Directorsdirectors declared the third quarter 20172018 dividends of $0.3275$0.345 per share each on Exelon's common stock. The third quarter 2017 dividendstock and was paid on September 8, 2017.10, 2018.

Table of Contents

Exelon's Boardboard of Directorsdirectors declared the fourth quarter 20172018 dividends of $0.3275$0.345 per share each on Exelon's common stock. The fourth quarter 2017 dividendstock and is payable on December 8, 2017.10, 2018.
All future quarterly dividends require approval by Exelon's Board of Directors.
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 20172018 and 2018.2019. 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 September 30, 2017,2018, the percentage of expected generation hedged is 98%-101%, 79%-82%82%-85% and 45%-48%48%-51% for 2017, 2018, 2019, and 20192020 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

199
Table of Contents


swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.
Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 60%59% of Generation’s uranium concentrate requirements from 20172018 through 20212022 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.positions.
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
President Trump and Congressional Republicans have stated that one of their top priorities is enactment of comprehensive tax reform.  On September 27, 2017, the Trump Administration and Republican Congressional leaders issued a unified framework which outlines their goals for comprehensive tax reform. Specifically, the framework proposes a reduction in the corporate tax rate from the current 35% to 20%, immediate expensing of new investments in depreciable assets for at least five years, elimination of the domestic production activities deduction and partial limitation of the deduction for interest. It is uncertain whether, to what extent, or when any changes in federal tax policies will be enacted or the transition time frame for such changes.  The Utility Registrants’ regulators may impose rate reductions to provide the benefit of any reduction in income tax expense to customers as well as to refund the "excess" deferred income taxes previously collected through rates.  The amount 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.
Environmental Legislative and Regulatory Developments
Exelon was actively involved in the Obama Administration’s development and implementation of environmental regulations for the electric industry, in pursuit of its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuelfossil fuel plants.

Table of Contents

Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.
In particular, the Administration has targeted certain existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings and withdrew all technical support documents supporting the calculation. Other regulations that have been specifically identified forare under review are

200
Table of Contents


include the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015 National Ambient Air Quality Standard (NAAQS) for ozone.Coal Combustion Residuals rule. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.
Air Quality
Mercury and Air Toxics Standard Rule (MATS). On December 16, 2011, the EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. The initial compliance deadline to meet the new standards was April 16, 2015; however, facilities may have been granted an additional one or two yeartwo-year extension in limited cases. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court to take further action consistent with the U.S. Supreme Court’s opinion on this single issue. On April 27, 2017, the D.C. Circuit granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. Notwithstanding the Court’s order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule.
Clean Power PlanPlan.. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. On October 10, 2017, EPA issued a proposed rule to repeal the CPP in its entirety, based on a proposed change in the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. The EPA has also indicated its intent to issueissued an advance notice of proposed rulemaking to solicit information on systems of emission reduction that are in accord with the Agency’s proposed revised legal interpretation; namely, only by regulating emission reductions that can be implemented at and to individual sources.

Table of Contents

2015 Ozone National Ambient Air Quality Standards (NAAQS). On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. EPA did not meetConcurrent with its review, the October 1, 2017 deadline to promulgate initialAgency issued several rounds of final ozone designations for areasthe 2015 ozone NAAQS in attainmentDecember 2017 and April 2018. On August 1, 2018, EPA filed a status report to the Court that indicated Agency does not intend to revise or non-attainmentrepeal the 2015 ozone standard at this time. Subsequently the Court ordered the case reactivated.
Primary SO2 National Ambient Air Quality Standards (NAAQS). On June 8, 2018, the EPA proposed to maintain the primary NAAQS for sulfur dioxide (SO2) at the same level and averaging time as was finalized by EPA in its 2010 SO2 NAAQS update. The schedule for completing this review is established by a consent decree, which sets January 28, 2019 as the deadline for signature on a final decision notice.
Climate Change. Exelon supports comprehensive climate change legislation or regulation which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In June 2018, Exelon joined the Climate Leadership Council, which advocates for a revenue neutral carbon tax and dividend program. In the absence of Federal legislation, the EPA has been reviewing the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the international regulation of GHG emissions pursuant to the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). See ITEM 1. BUSINESS, "Air Quality" of the standard. A number of states and environmental organizations have notified the EPA of their intent to file suit to compel EPA to issue the designations.Exelon 2017 Form 10-K for additional information.
Water Quality
Section 316(b) of the Clean Water Act requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by recent changes to the existing regulations. ThoseFor Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mountain Creek, Mystic Unit 7, Nine Mile Point Unit 1, Oyster Creek, Peach Bottom, Quad Cities, Riverside and Salem. See ITEM 1.—BUSINESS, "Water Quality" of the Exelon 20162017 Form 10-K for further discussion.

201
Table of Contents


additional information.
Solid and Hazardous Waste
In October 2015, the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants became effective. The rule classifiesclassified CCR as non-hazardous waste under RCRA. Under the regulation,RCRA, and CCR will continuecontinued to be regulated by most states subject to coordination with the federal regulations. In July 2018, the EPA issued a final rule amending the 2015 rule that provides more compliance flexibility to the states and owners and operators of coal ash disposal sites. Generation hascurrently does not own or operate any such sites subject to the CCR rule. Generation previously recorded accruals consistent with state regulation for its owned coal ash sites, and as such, the regulationCCR rule is not expected to impact Exelon’s and Generation’s financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted under the new federal regulationsCCR rule for coal ash disposal sites formerly owned by Generation. For these reasons, Generation is unable to predict whether and to what extent it may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations.
See Note 18—17 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further detailadditional information related to environmental matters, including the impact of environmental regulation.

Table of Contents

Other Legislative and Regulatory Developments
NRC Task Force on Fukushima Daiichi Accident (ExelonDelaware Distribution System Investment Charge
On June 14, 2018, the Governor of Delaware signed new Distribution System Investment Charge (DSIC) legislation, which establishes a system improvement charge that provides a mechanism to recover infrastructure investments, allowing for gradual rate increases and Generation).
In July 2011, an NRC Task Force formedlimiting frequency of distribution base rate cases.  DPL expects to make its first filing in Delaware in the aftermathfourth quarter of 2018, with 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 takennew charge effective in the nearfirst quarter of 2019.  While this legislation is expected to support needed infrastructure investment and longer term. The Task Force’s report concluded that nuclear reactors inallow for more timely recovery of those investments, Exelon, PHI and DPL cannot predict 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. 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 apotential financial impact standpoint. Generation’s current assessments are specificon Exelon, PHI or DPL.
Pennsylvania Alternative Ratemaking
On June 28, 2018, the Governor of Pennsylvania signed new legislation, which authorized the PAPUC to review and approve utility-proposed alternative rate mechanisms, including options such as decoupling mechanisms, formula rates, multi-year rate plans, and performance based rates.  Exelon and PECO cannot predict the Tier 1 recommendations. In May 2017,outcome or the NRC finalized its decision that no actions are required with respect to the Tier 2 and Tier 3 recommendations. Generation will continue to engage in nuclear industry assessments and actions and obtain stakeholder input.potential financial impact, if any, on Exelon or PECO.
Employees
In January 2017, an election was held at BGE which resulted in union representation for approximately 1,4001,394 employees. BGE and IBEW Local 410 have begun negotiations forare negotiating an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. Negotiations have been productive and continue. No agreement has been finalized to date and management cannot predict the outcome of such negotiations. In AprilNegotiations that began in 2017 Exelon Nuclearfor a first collective bargaining agreement with a small unit of employees represented by Local 501 of Operating Engineers at Exelon’s Hyperion Solutions facility are complete and the new CBA will expire in 2021. During 2017, Generation finalized CBAs with the Security Officer unions at LaSalle, Limerick and Quad Cities, which all will expire in 2020 and Dresden expiring in 2021. Additionally, during 2017, Generation acquired and combined two CBAs at Fitzpatrick into one CBA covering both craft and security employees, which will expire in 2023. Generation also successfully ratifiedfinalized the CBA with the IBEW union at TMI, which will expire in 2022. During 2018, Generation finalized its CBA with the SPFPASecurity Officer’s union at Braidwood, which will expire in 2021. Additionally, negotiations are currently underway for the two ACE Local 238 at Quad Cities210 contracts, which expire on October 15, 2018 and December 9, 2018. Both sides are bargaining in good faith and we anticipate a mutually acceptable outcome from these negotiations. As previously reported, there was an organizing effort over approximately 18 ACE control room System Operators. While an election was held with an outcome favorable to an extensionLocal 210, collective bargaining over this small segment of three years. In June 2017, Exelon Nuclear Security successfully ratified its CBA withemployees will not commence until the UGSOA Local 12 at Limerick to an extensionissue of three years.whether the System Operators are NLRA statutory supervisors is determined, and that matter is currently before the NLRB. 
Critical Accounting Policies and Estimates
Revenue Recognition (All Registrants)
Sources of Revenue and Determination of Accounting Treatment
The Registrants earn revenues from various business activities including: the sale of power and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail); the sale and delivery of power and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services.
The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from

Table of Contents

Contracts with Customers, Derivative and Alternative Revenue Program (ARP) guidance to recognize revenue as discussed in more detail below.
Revenue from Contracts with Customers
Under the Revenue from Contracts with Customers guidance, the Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power, natural gas, and other energy-related commodities are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as normal purchases and normal sales (NPNS), sales to utility customers under regulated service tariffs, and spot-market energy commodity sales, including settlements with independent system operators.
The determination of Generation’s and the Utility Registrants' retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally on a monthly basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the utilities’ customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternate supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged.
See Note 5 — Accounts Receivable of the Exelon 2017 Form 10-K for additional information on unbilled revenue.
See Note 1 — Significant Accounting Policies and Note 5 — Revenue from Contracts with Customers of the Combined Notes to Consolidated Financial Statements for additional information on the impacts of the new revenue accounting standard effective for annual reporting periods beginning on or after December 15, 2017.
Derivative Revenues
The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses include: inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses.
Alternative Revenue Program Revenues
Certain of the Utility Registrants’ ratemaking mechanisms qualify as Alternative Revenue Programs (ARPs) if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, which include the Utility Registrants’ formula rate and revenue decoupling mechanisms, the Utility Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income

Table of Contents

include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts.
See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — CRITICAL ACCOUNTING POLICIES AND ESTIMATES in Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's combined 20162017 Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, goodwill, purchase accounting, unamortized energy contract assets and liabilities, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies, revenue recognition and allowance for uncollectible accounts. At September 30, 2017,2018, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2016.2017.

202
Table of Contents


Results of Operations Byby Registrant
Net Income (Loss) Attributable to Common Shareholders by Registrant
Three Months Ended  
 September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended 
 September 30,		 
Favorable
(Unfavorable)
Variance
Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
2017 2016 2017 
2016(a)
 2018 2017 2018 2017 
Exelon$824
 $490
 $334
 $1,899
 $930
 $969
$733
 $823
 $(90) $1,858
 $1,907
 $(49)
Generation305
 236
 69
 479
 538
 (59)234
 304
 (70) 547
 487
 60
ComEd189
 37
 152
 447
 297
 150
193
 189
 4
 523
 447
 76
PECO112
 122
 (10) 327
 346
 (19)126
 112
 14
 336
 327
 9
BGE62
 54
 8
 231
 183
 48
63
 62
 1
 242
 231
 11
PHI187
 153
 34
 336
 359
 (23)
Pepco87
 79
 8
 188
 20
 168
89
 87
 2
 174
 188
 (14)
DPL31
 44
 (13) 107
 (16) 123
33
 31
 2
 90
 107
 (17)
ACE41
 47
 (6) 77
 (50) 127
61
 41
 20
 76
 77
 (1)
_________
(a)For Pepco, DPL and ACE, reflects that Registrant's operations for the nine months ended September 30, 2016. For Exelon and Generation, includes the operations of the PHI acquired businesses for the period of March 24, 2016 through September 30, 2016.
  Successor  Predecessor
  Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016  January 1, 2016 to March 23, 2016
PHI $153
 $166
 $359
 $(91)  $19

203
Table of Contents


Results of Operations — Generation
Three Months Ended  
 September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended 
 September 30,		 
Favorable
(Unfavorable)
Variance
Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
2017 2016 2017 2016 2018 2017 2018 2017 
Operating revenues$4,751
 $5,035
 $(284) $13,812
 $13,363
 $449
$5,278
 $4,750
 $528
 $15,368
 $13,843
 $1,525
Purchased power and fuel expense2,331
 2,589
 258
 7,286
 6,609
 (677)2,980
 2,331
 (649) 8,552
 7,286
 (1,266)
Revenues net of purchased power and fuel expense(a)
2,420
 2,446
 (26) 6,526
 6,754
 (228)2,298
 2,419
 (121) 6,816
 6,557
 259
Other operating expenses                      
Operating and maintenance1,374
 1,336
 (38) 4,871
 4,333
 (538)1,370
 1,376
 6
 4,126
 4,879
 753
Depreciation and amortization410
 632
 222
 1,046
 1,329
 283
468
 410
 (58) 1,383
 1,046
 (337)
Taxes other than income141
 136
 (5) 425
 380
 (45)143
 141
 (2) 414
 425
 11
Total other operating expenses1,925
 2,104
 179
 6,342
 6,042
 (300)1,981
 1,927
 (54) 5,923
 6,350
 427
(Loss) Gain on sales of assets(2) —
 (2) 3
 31
 (28)
(Loss) gain on sales of assets and businesses(6) (2) (4) 48
 3
 45
Bargain purchase gain7
 —
 7
 233
 —
 233
—
 7
 (7) —
 233
 (233)
Operating income500

342
 158
 420

743
 (323)311

497
 (186) 941

443
 498
Other income and (deductions)                      
Interest expense, net(113) (77) (36) (342) (273) (69)(101) (113) 12
 (305) (342) 37
Other, net209
 185
 24
 648
 395
 253
179
 209
 (30) 164
 648
 (484)
Total other income and (deductions)96
 108
 (12) 306
 122
 184
78
 96
 (18) (141) 306
 (447)
Income before income taxes596
 450
 146
 726
 865
 (139)389
 593
 (204) 800
 749
 51
Income taxes240
 173
 (67) 209
 293
 84
78
 239
 161
 110
 215
 105
Equity in losses of unconsolidated affiliates(8) (6) (2) (26) (16) (10)(11) (8) (3) (23) (26) 3
Net income348

271

77

491

556

(65)300

346

(46)
667

508

159
Net income attributable to noncontrolling interests43
 35
 (8) 12
 18
 6
66
 42
 (24) 120
 21
 (99)
Net income attributable to membership interest$305
 $236
 $69
 $479
 $538
 $(59)$234
 $304
 $(70) $547
 $487
 $60
_________
(a)Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue 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
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016.2017. Generation’s Net income attributable to membership interest for the three months ended September 30, 2017 increased2018 decreased compared to the same period in 2016,2017, primarily due to lower Depreciation and amortization expenses, a Bargain purchase gain in 2017, and higher other income, partially offset by lower Revenue net of purchased power and fuel expense, higher Depreciation and amortization expenses, lower Other income, partially offset by lower Operating and maintenance expenses and higher interest expense. The decrease in Depreciation and amortization is primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire Clinton and Quad Cities nuclear facilities. The Bargain purchase gain is primarily due to a measurement period adjustment for the FitzPatrick Acquisition. The increase in other income is primarily due to higher realized NDT fund gains.Income taxes. The decrease in Revenue net of purchased power and fuel expense primarily relates to the impactsabsence of lower load volumes delivered due to mild weatherEGTP

Table of Contents

revenues net of purchased power and fuel expense resulting from its deconsolidation in the fourth quarter of 2017, lower realized energy prices, lower energy efficiency revenues, decreased revenues related to Exelon's ratable hedging strategy,the sale of Generation's electrical contracting business in 2018 and increased nuclear outage days, partially offset by the impact of the New York CES,Illinois ZES and increased capacity prices. The decrease in Operating and maintenance expenses is primarily due to charges to earnings related to the acquisitionimpairment of the FitzPatrick nuclear facility,EGTP assets held for sale in 2017, decreased costs related to the sale of Generation's electrical contracting business in 2018 and decreased spending related to energy efficiency projects, partially offset by a decrease in nuclear outage days, increased capacity prices, and the additioncharge associated with a remeasurement of the two combined-cycle gas turbines in Texas.Oyster Creek ARO. The increase in OperatingDepreciation and maintenanceamortization is primarily due to accelerated depreciation and amortization expenses associated with Generation's decision to early retire the Oyster Creek and TMI nuclear facilities. The decrease in Other income is primarily due to the impairment of ExGen Texas Powerchange in 2017.realized and unrealized gains and losses on NDT funds. The increasedecrease in interest expenseIncome taxes is primarily due to tax savings related to the impact of project in-service dates on the capitalization of interest and higher outstanding debt.

204
Table of Contents


TCJA.
Nine Months Ended September 30, 20172018 Compared to Nine Months Ended September 30, 2016.2017.Generation’s Net income attributable to membership interest for the nine months ended September 30, 2017 decreased2018 increased compared to the same period in 2016,2017, primarily due to lowerhigher Revenue net of purchased power and fuel expense, higherlower Operating and maintenance expenses higherand lower Income taxes, other than income, and higher interest expense, partially offset by lowerhigher Depreciation and amortization expenses, a bargainBargain purchase gain in 2017 and higher otherlower Other income. The decreaseincrease in Revenue net of purchased power and fuel expense primarily relates to the conclusion of the Ginna Reliability Support Services Agreement, the impact of declining natural gas prices on Generation's natural gas portfolio, the impacts of lower load volumes due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES and Illinois ZES (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017), increased capacity prices, the acquisition of the FitzPatrick nuclear facility, increased capacity prices,decreased nuclear outage days, the addition of two combined-cycle gas turbines in Texas and the impacts of Generation's natural gas portfolio, partially offset by lower realized energy prices, the absence of oil inventory write downsEGTP revenues net of purchased power and fuel expense resulting from its deconsolidation in the fourth quarter of 2017, lower energy efficiency revenues and decreased fuel prices.revenues related to the sale of Generation's electrical contracting business in 2018. The increasedecrease in operatingOperating and maintenance expensesis primarily relatesdue to the impairment of EGTP assets held for sale compared to the impairment of upstream assets and certain wind projects in 2016, an increase in the number of2017, decreased nuclear outage days in 20172018, the impact of a supplemental NEIL distribution, certain costs associated with mergers and increased salaries, wagesacquisitions related to the PHI and contractingFitzPatrick acquisitions, decreased costs related to the sale of Generation's electrical contracting business in 2018 and decreased spending related to energy efficiency projects, partially offset by one-time charges associated with Generation's decision to early retire the TMI and Oyster Creek nuclear facilities. The increase in Depreciation and amortization is primarily due to accelerated depreciation and amortization expenses associated with Generation's decision to early retire the Oyster Creek and TMI nuclear facilities. The Bargain purchase gain in 2017 is due to the acquisition of the FitzPatrick nuclear facility. The increasedecrease in taxes other thanOther income relates to increased sales and use tax, increased gross receipts tax, and increased property taxes due to the FitzPatrick Acquisition. The increase in interest expense is primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt. The decreasechange in Depreciation and amortization is primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire Clinton and Quad Cities nuclear facilities. The bargain purchase gain is the result of the FitzPatrick acquisition in Q1 2017. The increase in other income is primarily due to increased unrealized gains and losses on NDT funds in 2017 compared to 2016.funds.
Revenues Net of Purchased Power and Fuel Expense
The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned with these same geographic regions. 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,

Table of Contents

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 AESO, OIESO and the Canadian portion of MISO.

205
Table of Contents


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 nuclear decommissioning; and other miscellaneous revenues.
Generation evaluates the operating performance of its electric business activities using the measure of Revenue 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.

Table of Contents

For the three and nine months ended September 30, 20172018 and 2016,2017, Generation’s Revenue net of purchased power and fuel expense by region were as follows:
Three Months Ended  
 September 30,		 Variance % Change Nine Months Ended 
 September 30,		 Variance % ChangeThree Months Ended
September 30,		 Variance % Change Nine Months Ended
September 30,		 Variance % Change
2017 2016 2017 2016 2018 2017 2018 2017 
Mid-Atlantic(a)
$855
 $887
 $(32) (3.6)% $2,411
 $2,556
 $(145) (5.7)%$763
 $855
 $(92) (10.8)% $2,348
 $2,411
 $(63) (2.6)%
Midwest(b)
697
 781
 (84) (10.8)% 2,140
 2,229
 (89) (4.0)%768
 697
 71
 10.2 % 2,400
 2,140
 260
 12.1 %
New England145
 160
 (15) (9.4)% 403
 350
 53
 15.1 %81
 145
 (64) (44.1)% 298
 403
 (105) (26.1)%
New York(d)
296
 194
 102
 52.6 % 678
 592
 86
 14.5 %292
 295
 (3) (1.0)% 841
 707
 134
 19.0 %
ERCOT118
 93
 25
 26.9 % 258
 231
 27
 11.7 %98
 118
 (20) (16.9)% 216
 258
 (42) (16.3)%
Other Power Regions68
 77
 (9) (11.7)% 220
 253
 (33) (13.0)%99
 68
 31
 45.6 % 309
 220
 89
 40.5 %
Total electric revenue net of purchased power and fuel expense2,179
 2,192
 (13) (0.6)% 6,110
 6,211
 (101) (1.6)%2,101
 2,178
 (77) (3.5)% 6,412
 6,139
 273
 4.4 %
Proprietary Trading4
 3
 1
 33.3 % 11
 9
 2
 22.2 %5
 4
 1
 25.0 % 39
 11
 28
 254.5 %
Mark-to-market (losses) gains73
 88
 (15) (17.0)% (161) (113) (48) 42.5 %
Mark-to-market gains (losses)71
 73
 (2) (2.7)% (104) (161) 57
 (35.4)%
Other(c)
164
 163
 1
 0.6 % 566
 647
 (81) (12.5)%121
 164
 (43) (26.2)% 469
 568
 (99) (17.4)%
Total revenue net of purchased power and fuel expense$2,420
 $2,446
 $(26) (1.1)% $6,526
 $6,754
 $(228) (3.4)%$2,298
 $2,419
 $(121) (5.0)% $6,816
 $6,557
 $259
 3.9 %
_________
(a)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 beginning on March 24, 2016, the day after the PHI merger was completed.region.
(b)Results of transactions with ComEd are included in the Midwest region.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes amortization of intangible assets related to commodity contracts recorded at fair value of a $19 million and $22 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017, and 2016, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 -8 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements of $6a $18 million decrease and $28$6 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 20172018 and 2016,2017, respectively. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of a $41 million and $15 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017, and 2016, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 -8 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements of $8a $53 million decrease and $38$8 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 20172018 and 2016,2017, respectively.
(d)Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

206
Table of Contents


Generation’s supply sources by region are summarized below:
Three Months Ended  
 September 30,		 Variance % Change Nine Months Ended 
 September 30,		 Variance % ChangeThree Months Ended
September 30,		 Variance % Change Nine Months Ended
September 30,		 Variance % Change
Supply source (GWhs)2017 2016 2017 2016 2018 2017 2018 2017 
Nuclear generation               
Nuclear Generation               
Mid-Atlantic(a)
16,480
 15,604
 876
 5.6 % 48,271
 47,035
 1,236
 2.6 %16,197
 16,480
 (283) (1.7)% 48,924
 48,271
 653
 1.4 %
Midwest24,362
 24,262
 100
 0.4 % 69,422
 70,925
 (1,503) (2.1)%23,834
 24,362
 (528) (2.2)% 70,532
 69,422
 1,110
 1.6 %
New York(d)(c)
6,905
 4,843
 2,062
 42.6 % 17,623
 14,002
 3,621
 25.9 %6,518
 6,905
 (387) (5.6)% 19,758
 17,623
 2,135
 12.1 %
Total Nuclear Generation47,747
 44,709
 3,038
 6.8 % 135,316

131,962
 3,354
 2.5 %46,549
 47,747
 (1,198) (2.5)% 139,214

135,316
 3,898
 2.9 %
Fossil and Renewables            

 

            

 

Mid-Atlantic596
 706
 (110) (15.6)% 2,330
 2,290
 40
 1.7 %853
 596
 257
 43.1 % 2,660
 2,330
 330
 14.2 %
Midwest218
 273
 (55) (20.1)% 1,053
 1,046
 7
 0.7 %244
 218
 26
 11.9 % 1,020
 1,053
 (33) (3.1)%
New England1,919
 1,886
 33
 1.7 % 5,921
 5,826
 95
 1.6 %1,339
 1,919
 (580) (30.2)% 4,189
 5,921
 (1,732) (29.3)%
New York1
 1
 —
 — % 3
 3
 —
 — %1
 1
 —
 — % 3
 3
 —
 — %
ERCOT5,703
 2,472
 3,231
 130.7 % 9,388
 5,726
 3,662
 64.0 %3,137
 5,703
 (2,566) (45.0)% 8,389
 9,388
 (999) (10.6)%
Other Power Regions2,149
 2,103
 46
 2.2 % 5,656
 6,245
 (589) (9.4)%2,289
 2,149
 140
 6.5 % 6,503
 5,656
 847
 15.0 %
Total Fossil and Renewables10,586
 7,441
 3,145
 42.3 % 24,351

21,136
 3,215
 15.2 %7,863
 10,586
 (2,723) (25.7)% 22,764

24,351
 (1,587) (6.5)%
Purchased Power            

 

            

 

Mid-Atlantic2,541
 7,139
 (4,598) (64.4)% 8,840
 14,024
 (5,184) (37.0)%3,504
 2,541
 963
 37.9 % 4,828
 8,840
 (4,012) (45.4)%
Midwest217
 461
 (244) (52.9)% 1,018
 1,855
 (837) (45.1)%174
 217
 (43) (19.8)% 733
 1,018
 (285) (28.0)%
New England4,513
 3,927
 586
 14.9 % 13,920
 11,863
 2,057
 17.3 %7,217
 4,513
 2,704
 59.9 % 18,607
 13,920
 4,687
 33.7 %
New York—
 —
 —
 — % 28
 —
 28
 — %—
 —
 —
 — % —
 28
 (28) (100.0)%
ERCOT1,199
 2,895
 (1,696) (58.6)% 5,724
 7,448
 (1,724) (23.1)%1,811
 1,199
 612
 51.0 % 5,504
 5,724
 (220) (3.8)%
Other Power Regions3,982
 3,803
 179
 4.7 % 10,357
 10,281
 76
 0.7 %5,488
 3,982
 1,506
 37.8 % 14,124
 10,357
 3,767
 36.4 %
Total Purchased Power12,452
 18,225
 (5,773) (31.7)% 39,887

45,471
 (5,584) (12.3)%18,194
 12,452
 5,742
 46.1 % 43,796

39,887
 3,909
 9.8 %
Total Supply/Sales by Region(b)
            

 

            

 

Mid-Atlantic(c)(b)
19,617
 23,449
 (3,832) (16.3)% 59,441
 63,349
 (3,908) (6.2)%20,554
 19,617
 937
 4.8 % 56,412
 59,441
 (3,029) (5.1)%
Midwest(c)(b)
24,797
 24,996
 (199) (0.8)% 71,493
 73,826
 (2,333) (3.2)%24,252
 24,797
 (545) (2.2)% 72,285
 71,493
 792
 1.1 %
New England6,432
 5,813
 619
 10.6 % 19,841
 17,689
 2,152
 12.2 %8,556
 6,432
 2,124
 33.0 % 22,796
 19,841
 2,955
 14.9 %
New York6,906
 4,844
 2,062
 42.6 % 17,654
 14,005
 3,649
 26.1 %6,519
 6,906
 (387) (5.6)% 19,761
 17,654
 2,107
 11.9 %
ERCOT6,902
 5,367
 1,535
 28.6 % 15,112
 13,174
 1,938
 14.7 %4,948
 6,902
 (1,954) (28.3)% 13,893
 15,112
 (1,219) (8.1)%
Other Power Regions6,131
 5,906
 225
 3.8 % 16,013
 16,526
 (513) (3.1)%7,777
 6,131
 1,646
 26.8 % 20,627
 16,013
 4,614
 28.8 %
Total Supply/Sales by Region70,785
 70,375
 410
 0.6 % 199,554

198,569
 985
 0.5 %72,606
 70,785
 1,821
 2.6 % 205,774

199,554
 6,220
 3.1 %
_________
(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 2,601 GWhs and 1,506 GWhs for the three months ended September 30, 2017 and 2016, respectively, and 6,763 GWhs and 4,015 GWhs for the nine months ended September 30, 2017 and 2016.
(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, includesregion and affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016.region.
(d)(c)Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

Table of Contents

Mid-Atlantic
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016.2017. The $32$92 million decrease in Revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower load volumes and lower realized energy prices, partially offset by decreased nuclear outage days and increased capacity prices.

207
Table of Contents


Nine Months Ended September 30, 20172018 Compared to Nine Months Ended September 30, 2016.2017. The $145$63 million decrease in Revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower load volumes, lower realized energy prices and decreased capacity prices, partially offset by the absence of oil inventory write-downs in 2017increased capacity prices and decreased nuclear outage days.
Midwest
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016.2017. The $84$71 million decreaseincrease in Revenue net of purchased power and fuel expense in the Midwest was primarily reflects lower realized energydue to the impact of the Illinois ZES and increased capacity prices, partially offset by increased capacity prices and decreased nuclear fuel prices.outage days.
Nine Months Ended September 30, 20172018 Compared to Nine Months Ended September 30, 2016.2017. The $89$260 million decreaseincrease in Revenue net of purchased power and fuel expense in the Midwest was primarily reflects lower realized energydue to the impact of the Illinois ZES (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017), increased capacity prices, and increaseddecreased nuclear outage days, partially offset by decreased fuellower realized energy prices.
New England
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016.2017. The $15$64 million decrease in Revenue net of purchased power and fuel expense in New England primarily reflects lower realized energy prices and decreased capacity prices.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017. The $105 million decrease in Revenue net of purchased power and fuel expense in New England primarily reflects lower realized energy prices, partially offset by increased capacity prices.
New York
NineThree Months Ended September 30, 20172018 Compared to NineThree Months Ended September 30, 2016. 2017.The $53$3 million increasedecrease in Revenue net of purchased power and fuel expense in New EnglandYork was driven byprimarily due to increased capacity prices,nuclear outage days and the resulting decreased ZEC revenues related to New York CES, partially offset by lowerhigher realized energy prices and increased capacity prices.
New York
ThreeNine Months Ended September 30, 20172018 Compared to ThreeNine Months Ended September 30, 2016.2017. The $102$134 million increase in Revenue net of purchased power and fuel expense in New York was primarily due to the impact of the New York CES and the acquisition of FitzPatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement and lower realized energy prices.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $86 million increase in Revenue net of purchased power and fuel expense in New York was primarily due to impact of the New York CES and the acquisition of FitzPatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement and lower realized energy prices.Q1 2017.
ERCOT
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016.2017. The $25$20 million increasedecrease in Revenue net of purchased power and fuel expense in ERCOT was primarily due to the deconsolidation of EGTP in 2017, partially offset by higher realized energy prices and the addition of two combined-cycle gas turbines in Texas.
Nine Months Ended September 30, 20172018 Compared to Nine Months Ended September 30, 2016.2017. The $27$42 million increasedecrease in Revenue net of purchased power and fuel expense in ERCOT was

Table of Contents

primarily due to the deconsolidation of EGTP in 2017, partially offset by the addition of two combined-cycle gas turbines in Texas partially offset by lowerand higher realized energy prices.
Other Power Regions
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016.2017. The $9$31 million decreaseincrease in Revenue net of purchased power and fuel expense in Other Power Regions was primarily due to lowerhigher realized energy prices.
Nine Months Ended September 30, 20172018 Compared to Nine Months Ended September 30, 2016. 2017.The $33$89 million decreaseincrease in Revenue net of purchased power and fuel expense in Other Power Regions was primarily due to lowerhigher realized energy prices.

208
Table of Contents


Proprietary Trading
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016.2017. The $1 million increase in Revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.
Nine Months Ended September 30, 20172018 Compared to Nine Months Ended September 30, 2016. 2017.The $2$28 million increase in Revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.
Mark-to-market
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016.2017. Mark-to-market gains on economic hedging activities were $71 million for the three months ended September 30, 2018 compared to gains of $73 million for the three months ended September 30, 2017 compared to gains of $88 million for the three months ended September 30, 2016.2017. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for additional information on gains and losses associated with mark-to-market derivatives.
Nine Months Ended September 30, 20172018 Compared to Nine Months Ended September 30, 2016. 2017.Mark-to-market losses on economic hedging activities were $104 million for the nine months ended September 30, 2018 compared to losses of $161 million for the nine months ended September 30, 2017 compared to losses of $113 million for the nine months ended September 30, 2016.2017. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for additional information on gains and losses associated with mark-to-market derivatives.
Other
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016.2017. The $1$43 million increasedecrease in Revenue net of purchased power and fuel expense in Other was due to the decline in revenues related to the distributed generationenergy efficiency business, offset by lowerthe sale of Generation's electrical contracting business in 2018, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - 8 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The $81 million decrease in other revenue netStatements, partially offset by the absence of purchased power and fuel was primarily due to the impacts of declining natural gas prices on Generation’s natural gas portfolio and amortization of energy contracts recorded at fair value associated with prior acquisitions, partially offset by revenueacquisitions.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017. The $99 million decrease in Revenue net of purchased power and fuel expense in Other was due to the decline in revenues related to the inclusionenergy efficiency business, the sale of Pepco Energy Services resultsGeneration's electrical contracting business in 20172018, and lower accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - 8 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements.Statements, partially offset by Generation's higher natural gas portfolio

Table of Contents

optimization and the absence of amortization of energy contracts recorded at fair value associated with prior acquisitions.
Nuclear Fleet Capacity Factor
The following table presents nuclear fleet operating data for the three and nine months ended September 30, 2017 as2018 compared to the same period in 2016,2017 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 to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.
Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2017 2016 2017 20162018 2017 2018 2017
Nuclear fleet capacity factor(a)
96.1% 96.3% 93.7% 94.8%93.6% 96.1% 94.4% 93.7%
Refueling outage days(a)
13
 17
 233
 174
36
 13
 198
 233
Non-refueling outage days(a)
15
 —
 35
 31
12
 15
 20
 35
_________
(a)Reflects ownership percentage of stations operated by Exelon. Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon. Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

209
Table of Contents


Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. The nuclear fleet capacity factor decreased primarily due to more non-refueling outage days and was partially offset by fewer refueling outage days, excluding Salem outages, during the three months ended September 30, 2017 compared to the same period in 2016.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. The nuclear fleet capacity factor decreased primarily due to more refueling and non-refueling outage days, excluding Salem outages, during the nine months ended September 30, 2017 compared to the same period in 2016.
Operating and Maintenance Expense
The changes in Operating and maintenance expense for the three and nine months ended September 30, 20172018 as compared to the same period in 2016,2017, consisted of the following:
 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
 
Increase (Decrease)(a)
 
Increase (Decrease)(a)
Labor, other benefits, contracting, materials(b)
$(8) $74
Nuclear refueling outage costs, including the co-owned Salem plants(c)
(12) 88
Corporate allocations19
 29
Merger and integration costs(d)
(4) 36
Merger commitments—
 (3)
Plant retirements and divestitures(e)
41
 (15)
Cost management program5
 (7)
ARO update(3) (4)
Long-lived asset impairments(f)
25
 288
Pension and non-pension postretirement benefits expense3
 4
Allowance for uncollectible accounts12
 35
Accretion expense(g)
10
 27
Other(50) (14)
Increase in operating and maintenance expense$38
 $538
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 
Increase (Decrease)(a)
 
Increase (Decrease)(a)
Labor, other benefits, contracting, materials(b)
$(50) $(163)
Nuclear refueling outage costs, including the co-owned Salem plants(c)
40
 (56)
Insurance(d)
(2) (38)
Merger and integration costs(e)
(11) (66)
Plant retirements and divestitures(f)
90
 47
Change in environmental liabilities(12) (5)
Long-lived asset impairments(g)
(33) (411)
Pension and non-pension postretirement benefits expense(7) (18)
Allowance for uncollectible accounts(3) (13)
Other(18) (30)
Decrease in Operating and maintenance expense$(6) $(753)
_________ 
(a)The 2017 financial results include Generation's acquisition of the FitzPatrick nuclear generating station from March 31, 2017.
(b)Reflects increased salaries, wagesPrimarily reflects decreased spending related to energy efficiency projects and contractingdecreased costs primarily related to the acquisitionsale of the FitzPatrick nuclear facility beginning on March 31, 2017.Generation's electrical contracting business in 2018.
(c)Primarily reflects a decreasean increase in the number of nuclear outage days for the three months ended September 30, 20172018 compared to 2016the same period in 2017 and an increasea decrease in the number of nuclear outage days for the nine months ended September 30, 20172018 compared to the same period in 2016.2017.
(d)ReflectsPrimarily reflects the impact of a supplemental NEIL insurance distribution.
(e)Primarily reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI and FitzPatrick acquisitions.
(e)Represents the announcement of the early retirement of Generation's TMI nuclear facilityacquisitions in 2017, compared toand the previous decision to early retire Generation's Clinton and Quad Cities nuclear facilitiesPHI acquisition in 2016.2018.
(f)Primarily reflects one-time charges associated with Generation’s decision to early retire the Oyster Creek nuclear facility including ARO in 2018 and the TMI nuclear facility in 2017.
(g)Primarily reflects charges to earnings related to impairments as a resultthe impairment of the EGTP assets held for sale in 2017, and in 2018 the impairment of Upstream assets and certain wind projects in 2016.
(g)Reflects the impact of increased accretion expenses primarily due to the acquisition of FitzPatrick on March 31, 2017.at Generation.
Depreciation and Amortization Expense
Depreciation and amortization expense for the three and nine months ended September 30, 20172018 compared to the three and nine months ended September 30, 2016 decreasedsame period in 2017 increased primarily due to lower accelerated depreciation and amortization as a result of the 2017due to Generation's decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the ClintonOyster Creek and Quad CitiesTMI nuclear facilities.
Taxes Other Than Income
Taxes other than income, taxes, which can vary period to period, include non-income municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 20172018 compared to the three and nine months ended September 30, 2016 increased primarily due to increased property

210
Table of Contents


taxes as a result of the addition of FitzPatrick, increased gross receipts tax expense, and increased sales and use tax expense.same period in 2017 remained relatively consistent.
(Loss) gain on Sales of Assets and Businesses
Loss on sales of assets and businesses for the three months ended September 30, 20172018 compared to the three months ended September 30, 2016same period in 2017 remained relatively stable.consistent. Gain on sales of assets and businesses for the nine months ended September 30, 20172018 compared to the nine months ended September 30, 2016 decreasedsame period in 2017 increased primarily due to the gain associated with Generation's 2018 sale of the New Boston generating site in 2016.its electrical contracting business.

Table of Contents

Bargain Purchase Gain
Bargain purchase gain for the three and nine months ended September 30, 20172018 compared to the three and nine months ended September 30, 2016 increasedsame period in 2017 decreased as a result of the gain associated with the FitzPatrick acquisition. Refer toacquisition in 2017. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.
Interest Expense, netNet
Interest expense, net for the three and nine months ended September 30, 20172018 compared to the three and nine months ended September 30, 2016 increasedsame period in 2017 primarily reflects decreased interest expense due to the impactretirement of project in-service dates on the capitalization of interest and higher outstandinglong-term debt.
Other, Net
Other, net for the three and nine months ended September 30, 20172018 compared to the three and nine months ended September 30, 2016 increasedsame period in 2017 decreased primarily due to the change in the realized and unrealized gains and losses related to NDT funds of Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $37$29 million and $39$37 million for the three months ended September 30, 20172018 and 2016,2017, respectively, and $129$24 million and $84$129 million for the nine months ended September 30, 20172018 and 2016,2017, respectively, related to the contractual elimination of income tax expense (benefit) associated with the NDT funds of the Regulatory Agreement Units. Refer toSee Note 13 — Nuclear DecommissioningAsset Retirement Obligations of the Combined Notes to the Consolidated Financial Statements for additional information regarding NDT funds.
The following table provides unrealized and realized gains and losses on the NDT funds of the Non-Regulatory Agreement Units recognized in Other, net for the three and nine months ended September 30, 20172018 and 2016:2017:
Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2017 2016 2017 20162018 2017 2018 2017
Net unrealized gains on decommissioning trust funds$111

$116
 $347
 $216
Net unrealized gains (losses) on decommissioning trust funds$72

$111
 $(143) $347
Net realized gains on sale of decommissioning trust funds33
 12
 82
 26
29
 33
 164
 82
Equity in Losses of Unconsolidated Affiliates
Equity in losses of unconsolidated affiliates for the three and nine months ended September 30, 20172018 compared to the three and nine ended September 30, 2016same period in 2017 remained relatively stable.consistent.
Effective Income Tax Rate
Generation's effective income tax rate was 40.3%20.1% and 38.4%40.3% for the three months ended September 30, 20172018 and 2016,2017, respectively. Generation's effective income tax rate was 28.8%13.8% and 33.9%28.7% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and 2016, respectively.nine months ended September 30, 2018 compared to the same periods in 2017 is primarily related to tax savings due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussionadditional information of the change in the effective income tax rate.

211
Table of Contents


Results of Operations — ComEd
Three Months Ended  
 September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended 
 September 30,		 
Favorable
(Unfavorable)
Variance
Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
2017 2016 2017 2016 2018 2017 2018 2017 
Operating revenues$1,571
 $1,497
 $74
 $4,227
 $4,031
 $196
$1,598
 $1,571
 $27
 $4,508
 $4,227
 $281
Purchased power expense529
 454
 (75) 1,241
 1,141
 (100)619
 529
 (90) 1,702
 1,241
 (461)
Revenues net of purchased power expense(a)(b)
1,042
 1,043
 (1) 2,986
 2,890
 96
979
 1,042
 (63) 2,806
 2,986
 (180)
Other operating expenses                      
Operating and maintenance346
 377
 31
 1,096
 1,113
 17
337
 346
 9
 974
 1,096
 122
Depreciation and amortization212
 196
 (16) 631
 574
 (57)237
 212
 (25) 696
 631
 (65)
Taxes other than income80
 82
 2
 223
 222
 (1)82
 80
 (2) 238
 223
 (15)
Total other operating expenses638
 655
 17
 1,950
 1,909
 (41)656
 638
 (18) 1,908
 1,950
 42
Gain on sales of assets—
 1
 (1) —
 6
 (6)—
 —
 —
 5
 —
 5
Operating income404
 389
 15
 1,036
 987
 49
323
 404
 (81) 903
 1,036
 (133)
Other income and (deductions)                      
Interest expense, net(89) (197) 108
 (275) (374) 99
(85) (89) 4
 (261) (275) 14
Other, net5
 (80) 85
 14
 (72) 86
7
 5
 2
 21
 14
 7
Total other income and (deductions)(84) (277) 193
 (261) (446) 185
(78) (84) 6
 (240) (261) 21
Income before income taxes320
 112
 208
 775
 541
 234
245
 320
 (75) 663
 775
 (112)
Income taxes131
 75
 (56) 328
 244
 (84)52
 131
 79
 140
 328
 188
Net income$189
 $37
 $152
 $447
 $297
 $150
$193
 $189
 $4
 $523
 $447
 $76
_________
(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
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016. 2017.ComEd’s Net income for the three months ended September 30, 20172018 was higher than the same period in 2016,2017 primarily due to the recognition of the penalty and the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016 and increasedhigher electric distribution and transmissionenergy efficiency formula rate earnings (reflectingearnings. The TCJA did not significantly impact ComEd's net income for the three months ended September 30, 2018 as the favorable income tax impacts of increased capital investment and higher allowed electric distribution ROE). The higher Net income was partiallywere predominantly offset by lower revenues resulting from the impactpass back of weather conditions in the third quarter of 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.tax savings through customer rates.
Nine Months Ended September 30, 20172018 Compared to Nine Months Ended September 30, 2016. 2017.ComEd’s Net income for the nine months ended September 30, 20172018 was higher than the same period in 2016,2017 primarily due to the recognition of the penalty and the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016 and increasedhigher electric distribution and transmissionenergy efficiency formula rate earnings (reflecting the impacts of increased capital investment and higher allowed electric distribution ROE). The higher Net income was partially offset byas well as additional tax and interest recorded in the second quarter of 2017 relating to Exelon's like-kind exchange tax position andposition. The TCJA did not significantly impact ComEd's net income for the impact of weather conditions in the second and third quarters of 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.nine

212
Table of Contents


months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Revenues Net of Purchased Power Expense
There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC, and ZEC procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity, REC, and ZEC procurement costs from retail customers without mark-up. Therefore, these costs have no significant impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K 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 three and nine months ended September 30, 2017 and 2016, consisted of the following:
 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
Electric68% 70% 70% 72%
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:
 September 30, 2017 September 30, 2016
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric1,360,800
 34% 1,526,900
 39%
The changes in ComEd’s Revenue net of purchased power expense for the three and nine months ended September 30, 2017, compared to the same period in 2016 consisted of the following:
 Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017
 Increase (Decrease) Increase (Decrease)
Weather(a)
$(34) $(37)
Volume(a)
(5) (11)
Electric distribution revenue59
 119
Transmission revenue11
 45
Energy efficiency revenue(b)
5
 6
Regulatory required programs(b)
(39) (24)
Uncollectible accounts recovery, net(3) (5)
Pricing and customer mix(a)
—
 (1)
Other5
 4
Total increase (decrease)$(1) $96
_________
(a)These changes only reflect the 2016 impacts of weather, volume, and pricing and customer mix. As further described below, pursuant to the revenue decoupling provision in FEJA, ComEd began recording an adjustment to revenue in the first quarter of 2017 to eliminate the favorable or unfavorable impacts associated with variations in delivery volumes associated with above or below normal weather, number of customers or usage per customer.
(b)Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.
Revenue Decoupling. 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.

213
Table of Contents


Under EIMA, ComEd's electric distribution formula rate provided for an adjustment to future billings if its earned ROE fell outside a 50 bps collar of its allowed ROE, which partially eliminated the impacts of weather and load on ComEd's revenue. As allowed under FEJA, ComEd will revise its electric distribution formula rate to eliminate the ROE collar beginning with the reconciliation filed in 2018 for the 2017 calendar year. Elimination of the ROE collar effectively offsets the favorable or unfavorable impacts to Operating revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer. ComEd began recognizing the impacts of this change beginning in the first quarter of 2017. During the three and nine months ended September 30, 2017, ComEd recorded a decrease to Electric distribution revenues of approximately $15 million and an increase to Electric distribution revenues of approximately $21 million, respectively, to eliminate weather and load impacts.
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 three and nine months ended September 30, 2017 and 2016, consisted of the following:
Heating and Cooling Degree-Days    % Change
Three Months Ended September 30,2017 2016 Normal2017 vs. 2016 2017 vs. Normal
Heating Degree-Days42
 23
 97
 82.6 % (56.7)%
Cooling Degree-Days699
 840
 641
 (16.8)% 9.0 %
          
Nine Months Ended September 30,         
Heating Degree-Days3,269
 3,678
 3,972
 (11.1)% (17.7)%
Cooling Degree-Days962
 1,130
 882
 (14.9)% 9.1 %
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. 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. Electric distribution revenue increased during the three and nine months ended September 30, 2017, primarily due to increased capital investment, increased Depreciation expense, and higher allowed ROE due to an increase in treasury rates as compared to the same period in 2016 and due to revenue decoupling impacts (as described above) during the nine months ended September 30, 2017. See Depreciation and amortization expense discussions below, and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. For the three and nine months ended September 30, 2017, ComEd recorded increased transmission revenue due to increased capital investment, higher Depreciation expense and increased highest daily peak load as compared to the same period in 2016. See Operating and maintenance expense below and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue. Beginning June 1, 2017, FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year.  Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE 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

214
Table of Contents


savings goal. See Depreciation and amortization expense discussions below, and Note 5 — 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 rate riders to recover costs incurred for regulatory programs such as ComEd’s purchased power administrative costs and energy efficiency and demand response through June 1, 2017 pursuant to FEJA. The riders are designed to provide full and current cost recovery. 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.
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
 Three Months Ended  
 September 30,		 
Increase
(Decrease)
 Nine Months Ended 
 September 30,		 Increase (Decrease)
 2017 2016  2017 2016 
Operating and maintenance expense — baseline$344
 $336
 $8
 $1,000
 $993
 $7
Operating and maintenance expense — regulatory required programs(a)
2
 41
 $(39) 96
 120
 (24)
Total operating and maintenance expense$346

$377

$(31)
$1,096

$1,113

$(17)
_________
(a)Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
The increase in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:
 Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor, other benefits, contracting and materials$(5) $(11)
Pension and non-pension postretirement benefits expense1
 2
Storm-related costs1
 1
Uncollectible accounts expense — provision(a)
(4) (8)
Uncollectible accounts expense — recovery, net(a)
1
 3
BSC costs(b)
21
 35
Other(7) (15)
 8
 7
Regulatory required programs   
Energy efficiency and demand response programs(c)
(39) (24)
Decrease in operating and maintenance expense$(31) $(17)
_________
(a)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. During the three and nine months ended September 30, 2017, ComEd recorded a net decrease in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting decrease has been recognized in Operating revenues for the period presented.
(b)For the three and nine months ended September 30, 2017, includes the $8 million write-off of a regulatory asset related to Constellation merger and integration costs for which recovery is no longer expected.
(c)Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

215
Table of Contents


Depreciation and Amortization Expense
The increase in Depreciation and amortization expense during the three and nine months ended September 30, 2017, compared to the same period in 2016, consisted of the following:
 Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017
 Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$14
 $47
Regulatory asset amortization(b)
1
 2
Other1
 8
Total increase$16
 $57
_________
(a)Primarily reflects ongoing capital expenditures for the three and nine months ended September 30, 2017.
(b)Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset.
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 three and nine months ended September 30, 2017, compared to the same period in 2016.
Gain on Sales of Assets
The decrease in Gain on sales of assets during the nine months ended September 30, 2017, compared to the same period in 2016, is primarily due to the sale of land during March 2016.
Interest Expense, Net
The changes in interest expense, net, for the three and nine months ended September 30, 2017, compared to the same period in 2016, consisted of the following:
 Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017
 Increase (Decrease) Increase (Decrease)
Interest expense related to uncertain tax positions(a)
$(110) $(103)
Interest expense on debt (including financing trusts)(1) 3
Other3
 1
Decrease in interest expense, net$(108) $(99)
_________
(a)Primarily reflects the recognition of the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016, partially offset by additional interest recorded in the second quarter of 2017 related to Exelon's like-kind exchange tax position.
Other, Net
Other, net, decreased during the three and nine months ended September 30, 2017, compared to the same period in 2016 primarily due to 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.
Effective Income Tax Rate
ComEd's effective income tax rate was 40.9% and 67.0% for the three months ended September 30, 2017 and 2016, respectively. ComEd's effective income tax rate was 42.3% and 45.1% for the nine months ended September 30, 2017 and 2016, respectively. The decreases in the effective income tax rates for the three and nine months ended September 30, 2017 as compared to the same period in 2016 are primarily due to a non-deductible penalty incurred in 2016. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

216
Table of Contents


ComEd Electric Operating Statistics and Revenue Detail
  Three Months Ended  
 September 30,		 % Change 
Weather-
Normal
%  Change
 Nine Months Ended 
 September 30,		 % Change 
Weather-
Normal
%  Change
Retail Deliveries to Customers (in GWhs)2017 2016  2017 2016 
Retail Deliveries(a)
               
Residential8,004
 9,014
 (11.2)% (0.6)% 20,164
 21,738
 (7.2)% (1.3)%
Small commercial & industrial8,488
 8,833
 (3.9)% (1.0)% 23,634
 24,447
 (3.3)% (1.6)%
Large commercial & industrial7,232
 7,565
 (4.4)% (2.5)% 20,712
 21,057
 (1.6)% (0.5)%
Public authorities & electric railroads302
 308
 (1.9)% (1.7)% 928
 947
 (2.0)% (1.4)%
Total retail deliveries24,026

25,720
 (6.6)% (1.3)% 65,438

68,189
 (4.0)% (1.1)%
 As of September 30,
Number of Electric Customers2017 2016
Residential3,610,091
 3,578,846
Small commercial & industrial376,309
 372,603
Large commercial & industrial1,954
 2,010
Public authorities & electric railroads4,763
 4,738
Total3,993,117

3,958,197
 Three Months Ended  
 September 30,		   Nine Months Ended 
 September 30,		  
Electric Revenue2017 2016 
%
Change
 2017 2016 
%
Change
Retail Sales(a)
           
Residential$825
 $786
 5.0 % $2,108
 $2,018
 4.5%
Small commercial & industrial369
 356
 3.7 % 1,051
 1,007
 4.4%
Large commercial & industrial121
 126
 (4.0)% 352
 350
 0.6%
Public authorities & electric railroads11
 10
 10.0 % 34
 33
 3.0%
Total retail1,326
 1,278
 3.8 % 3,545
 3,408
 4.0%
Other revenue(b)
245
 219
 11.9 % 682
 623
 9.5%
Total electric revenue(c)
$1,571
 $1,497
 4.9 % $4,227
 $4,031
 4.9%
_________
(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.
(c)Includes operating revenues from affiliates totaling $3 million and $4 million for the three and nine months ended September 30, 2017 and 2016, and $12 million and $12 million for the nine months ended September 30, 2017 and 2016, respectively.

217
Table of Contents


Results of Operations — PECO
 Three Months Ended  
 September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended 
 September 30,		 Favorable
(Unfavorable)
Variance
 2017 2016  2017 2016 
Operating revenues$715
 $788
 $(73) $2,141
 $2,293
 $(152)
Purchased power and fuel expense235
 272
 37
 719
 809
 90
Revenues net of purchased power and fuel expense(a)
480
 516
 (36) 1,422
 1,484
 (62)
Other operating expenses           
Operating and maintenance197
 199
 2
 595
 604
 9
Depreciation and amortization72
 67
 (5) 213
 201
 (12)
Taxes other than income42
 46
 4
 116
 126
 10
Total other operating expenses311
 312
 1
 924
 931
 7
Operating income169
 204
 (35) 498
 553
 (55)
Other income and (deductions)           
Interest expense, net(31) (30) (1) (93) (92) (1)
Other, net2
 2
 —
 6
 6
 —
Total other income and (deductions)(29) (28) (1) (87) (86) (1)
Income before income taxes140
 176
 (36) 411
 467
 (56)
Income taxes28
 54
 26
 84
 121
 37
Net income$112
 $122
 $(10) $327
 $346
 $(19)
_________
(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 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 presentations 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
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016. 2017.PECO's ComEd’s Net income decreased fromfor the three months ended September 30, 2018 was higher than the same period in 2016,2017 primarily due to higher electric distribution and energy efficiency formula rate earnings. The TCJA did not significantly impact ComEd's net income for the three months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower Revenues netrevenues resulting from the pass back of purchased power and fuel from unfavorable weather conditions in PECO's service territory.the tax savings through customer rates.
Nine Months Ended September 30, 20172018 Compared to Nine Months Ended September 30, 2016. 2017.PECO's ComEd’s Net income decreased from the same period in 2016, primarily due to lower Revenues net of purchased power and fuel from unfavorable weather conditions in PECO's service territory.
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 at least quarterly 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 the PAPUC's GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and natural gas revenue 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 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. Customer choice program activity has no impact on electric and natural gas revenue net of purchased power and fuel expense.

218
Table of Contents


Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30, 2017 and 2016, consisted of the following:
 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
Electric70% 69% 71% 70%
Natural Gas29% 31% 26% 26%
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:
 September 30, 2017 September 30, 2016
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric570,500
 35% 581,600
 36%
Natural Gas82,600
 16% 81,300
 16%
The changes in PECO’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same period in 2016 consisted of the following:
 Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017
 Increase (Decrease) Increase (Decrease)
 Electric Natural Gas Total Electric Natural Gas Total
Weather$(48) $—
 $(48) $(45) $(3) $(48)
Volume—
 1
 1
 (12) 4
 (8)
Pricing9
 —
 9
 13
 —
 13
Regulatory required programs(6) —
 (6) (29) —
 (29)
Other7
 1
 8
 10
 —
 10
Total decrease$(38) $2
 $(36) $(63) $1
 $(62)
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended September 30, 2017 compared to the same period in 2016, Operating revenue net of purchased power decreased due to unfavorable summer weather conditions. Operating revenue net of fuel expense was relatively consistent. During the nine months ended September 30, 2017 compared to the same period in 2016, Operating revenue net of purchased power and fuel expense decreased due to unfavorable weather conditions.

219
Table of Contents


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 three and nine months ended September 30, 2017 compared to the same periods in 2016 and normal weather consisted of the following:
Heating and Cooling Degree-Days  Normal % Change
Three Months Ended September 30,2017 20162017 vs. 2016 2017 vs. Normal
Heating Degree-Days14
 10
 35
 40.0 % (60.0)%
Cooling Degree-Days989
 1,288
 923
 (23.2)% 7.2 %
          
Nine Months Ended September 30,         
Heating Degree-Days2,437
 2,616
 2,974
 (6.8)% (18.1)%
Cooling Degree-Days1,404
 1,684
 1,271
 (16.6)% 10.5 %
Volume. Operating revenue net of purchased power and fuel related to delivery volume, exclusive of the effects of weather, remained relatively consistent for the three months ended September 30, 2017 compared to the same period in 2016. The decrease in Operating revenue net of purchased power related to delivery volume, exclusive of the effects of weather, for the nine months ended September 30, 2017 compared to the same period in 2016, primarily reflects the impacts of energy efficiency initiatives on customer usage partially offset by moderate economic and customer growth, as well as a shift in the volume profile across classes from residential and small commercial and industrial to large commercial and industrial. Operating revenue net of fuel expense for the nine months ended September 30, 2017 compared to the same period in 2016 increased due to strong customer growth and moderate economic growth.
Pricing. Operating revenues net of purchased power as a result of pricing for the three and nine months ended September 30, 2017 compared to the same period in 2016 increased primarily due to higher overall effective rates due to decreased usage across the major customer classes. Operating revenues net of fuel expense for the three and nine months ended September 30, 2017 compared to the same period in 2016 remained relatively consistent.
Regulatory Required Programs. This represents the change in Operating revenue collected under approved riders to recover costs incurred for regulatory programs such as 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
 Three Months Ended  
 September 30,		 
Increase
(Decrease)
 Nine Months Ended 
 September 30,		 Increase
(Decrease)
 2017 2016  2017 2016 
Operating and maintenance expense — baseline$183
 $185
 $(2) $552
 $545
 $7
Operating and maintenance expense — regulatory required programs(a)
14
 14
 —
 43
 59
 (16)
Total operating and maintenance expense$197
 $199
 $(2) $595
 $604
 $(9)
_________
(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.

220
Table of Contents


The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:
 Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor, other benefits, contracting and materials$7
 $14
Storm-related costs(3) (7)
Pension and non-pension postretirement benefits expense(1) (2)
PHI merger and integration costs1
 1
BSC costs5
 6
Uncollectible accounts expense(6) (6)
Other(5) 1
 (2) 7
Regulatory Required Programs   
Energy efficiency1
 (15)
Other(1) (1)
 —
 (16)
Total decrease$(2) $(9)
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:
 Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017
 Increase (Decrease) Increase (Decrease)
Depreciation and amortization expense$5
 $13
Regulatory asset amortization—
 (1)
Total increase$5
 $12
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income decreased for the three and nine months ended September 30, 2017 compared to the same period in 2016 due to a decrease in gross receipts tax driven by a decrease in electric revenue.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2017 remained consistent compared to the same period in 2016.
Other, Net
Other, net for the three and nine months ended September 30, 2017 remained consistent compared to the same period in 2016.
Effective Income Tax Rate
PECO's effective income tax rate was 20.0% and 30.7% for the three months ended September 30, 2017 and 2016, respectively, and 20.4% and 25.9% for the nine months ended September 30, 2017 and 2016, respectively. See

221
Table of Contents


Note 12 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.
PECO Electric Operating Statistics and Revenue Detail
  Three Months Ended  
 September 30,		 % Change 
Weather -
Normal
% Change
 Nine Months Ended 
 September 30,		 % Change Weather -
Normal
% Change
Retail Deliveries to Customers (in GWhs)2017 2016  2017 2016 
Retail Deliveries(a)
               
Residential3,752
 4,358
 (13.9)% 0.2 % 9,939
 10,682
 (7.0)% (1.4)%
Small commercial & industrial2,158
 2,324
 (7.1)% (1.0)% 6,048
 6,236
 (3.0)% (1.1)%
Large commercial & industrial4,137
 4,234
 (2.3)% 1.4 % 11,593
 11,598
 — % 0.8 %
Public authorities & electric railroads198
 240
 (17.5)% (17.5)% 618
 672
 (8.0)% (8.0)%
Total retail deliveries10,245

11,156
 (8.2)% — % 28,198

29,188
 (3.4)% (0.6)%
  As of September 30,
Number of Electric Customers2017 2016
Residential1,463,906
 1,451,533
Small commercial & industrial150,964
 149,646
Large commercial & industrial3,112
 3,094
Public authorities & electric railroads9,665
 9,820
Total1,627,647
 1,614,093
 Three Months Ended  
 September 30,		 % Change Nine Months Ended 
 September 30,		 % Change
Electric Revenue2017 2016  2017 2016 
Retail Sales(a)
           
Residential$434
 $513
 (15.4)% $1,147
 $1,278
 (10.3)%
Small commercial & industrial106
 109
 (2.8)% 303
 334
 (9.3)%
Large commercial & industrial59
 59
 — % 168
 182
 (7.7)%
Public authorities & electric railroads7
 8
 (12.5)% 23
 25
 (8.0)%
Total retail606
 689
 (12.0)% 1,641
 1,819
 (9.8)%
Other revenue(b)
56
 51
 9.8 % 161
 152
 5.9 %
Total electric revenue(c)
$662
 $740
 (10.5)% $1,802
 $1,971
 (8.6)%
_________
(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.
(b)Other revenue primarily includes transmission revenue from PJM and wholesale electric revenue, in addition to rental income.
(c)Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended September 30, 2017 and 2016, respectively, and $4 million and $5 million for the nine months ended September 30, 2017 and 2016, respectively.
PECO Natural Gas Operating Statistics and Revenue Detail
 Three Months Ended  
 September 30,		 % Change 
Weather -
 Normal
% Change
 Nine Months Ended 
 September 30,		 % Change 
Weather -
 Normal
% Change
Deliveries to Customers (in mmcf)2017 2016  2017 2016 
Retail Delivery               
Retail sales(a)
3,993
 3,494
 14.3 % 9.4 % 38,825
 38,488
 0.9 % 2.7 %
Transportation and other5,674
 7,315
 (22.4)% (14.5)% 19,122
 20,917
 (8.6)% (5.9)%
Total natural gas deliveries9,667
 10,809
 (10.6)% (6.0)% 57,947
 59,405
 (2.5)% (0.1)%

222
Table of Contents


 As of September 30,
Number of Natural Gas Customers2017 2016
Residential474,766
 470,024
Commercial & industrial43,358
 42,997
Total retail518,124

513,021
Transportation771
 802
Total518,895

513,823
  Three Months Ended  
 September 30,		 % Change Nine Months Ended 
 September 30,		 % Change
Natural Gas Revenue2017 2016  2017 2016 
Retail Sales           
Retail sales(a)
$46
 $41
 12.2% $315
 $298
 5.7%
Transportation and other7
 7
 —% 24
 24
 —%
Total natural gas revenues(b)
$53

$48
 10.4% $339

$322
 5.3%
_________
(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)Includes operating revenues from affiliates totaling less than $1 million for the three and nine months ended September 30, 2017 and 2016.

223
Table of Contents


Results of Operations — BGE
 Three Months Ended  
 September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended 
 September 30,		 
Favorable
(Unfavorable)
Variance
 2017 2016  2017 2016 
Operating revenues$738
 $812
 $(74) $2,363
 $2,421
 $(58)
Purchased power and fuel expense269
 360
 91
 853
 994
 141
Revenues net of purchased power and fuel expense(a)
469
 452
 17
 1,510
 1,427
 83
Other operating expenses           
Operating and maintenance175
 178
 3
 532
 588
 56
Depreciation and amortization109
 101
 (8) 348
 307
 (41)
Taxes other than income61
 58
 (3) 180
 172
 (8)
Total other operating expenses345
 337
 (8) 1,060
 1,067
 7
Operating income124
 115
 9
 450
 360
 90
Other income and (deductions)           
Interest expense, net(26) (28) 2
 (80) (76) (4)
Other, net4
 5
 (1) 12
 16
 (4)
Total other income and (deductions)(22) (23) 1
 (68) (60) (8)
Income before income taxes102
 92
 10
 382
 300
 82
Income taxes40
 36
 (4) 151
 109
 (42)
Net income62
 56
 6
 231
 191
 40
Preference stock dividends—
 2
 2
 —
 8
 8
Net income attributable to common shareholder$62
 $54
 $8
 $231
 $183
 $48
_________
(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
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. BGE’s Net income attributable to common shareholder for the three months ended September 30, 20172018 was higher than the same period in 2016,2017 primarily due to an increase in Revenues net of purchased powerhigher electric distribution and fuel expense, predominantly as a result of an increase in transmissionenergy efficiency formula rate revenues. This item was partially offset by an increaseearnings as well as additional tax and interest recorded in Depreciation and amortization expense primarily relatedthe second quarter of 2017 relating to the impacts of increased capital investment.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. BGE’s NetExelon's like-kind exchange tax position. The TCJA did not significantly impact ComEd's net income attributable to common shareholder for the nine months ended September 30, 2017 was higher than the same period in 2016, primarily due to an increase in Revenues net of purchased power and fuel expense and lower Operating and maintenance expense. The increase in Revenues net of purchased power and fuel expense was primarily due to the impacts of the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016 and an increase in transmission formula rate revenues. The lower Operating and maintenance expense was primarily due to the absence of cost disallowances resulting from the 2016 distribution rate orders issued by the MDPSC and decreased storm costs in 2017. These items were partially offset by higher income tax expense primarily resulting from a cumulative adjustment to reduce tax expense in 2016 for transmission-related regulatory assets and an increase in Depreciation and amortization expense primarily related to the initiation of cost recovery of the AMI programs under the distribution rate orders and the impacts of increased capital investment.

224
Table of Contents


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. The 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.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30, 2017 and 2016 consisted2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the following:
 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
Electric60% 58% 60% 59%
Natural Gas74% 80% 57% 59%
The number of retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:
 September 30, 2017 September 30, 2016
 Number of Customers % of total retail customers Number of customers % of total retail customers
Electric339,300
 27% 334,100
 26%
Natural Gas148,600
 22% 150,000
 23%
The changes in BGE’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2017, compared to the same period in 2016, consisted of the following:
 Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017
 Increase (Decrease) Increase (Decrease)
 Electric Gas Total Electric Gas Total
Distribution rate increase$—
 $—
 $—
 $21
 $29
 $50
Regulatory required programs2
 —
 2
 11
 1
 12
Transmission revenue7
 —
 7
 10
 —
 10
Other, net4
 4
 8
 5
 6
 11
Total increase$13
 $4
 $17
 $47
 $36
 $83
Distribution Rate Increase. The increase in distribution revenues for the nine months ended September 30, 2017, compared to the same period in 2016, was primarily due to the impact of the electric and natural gas distribution rates charged to customers that became effective in June 2016 in accordance with the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

225
Table of Contents


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 pertax savings through 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 fluctuations in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved distribution charges 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 three and nine months ended September 30, 2017 compared to the same period in 2016 consisted of the following:
Heating and Cooling Degree-Days      % Change
Three Months Ended September 30,2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days64
 24
 78
 166.7 % (17.9)%
Cooling Degree-Days595
 747
 596
 (20.3)% (0.2)%
          
Nine Months Ended September 30,         
Heating Degree-Days2,524
 2,878
 2,992
 (12.3)% (15.6)%
Cooling Degree-Days877
 966
 850
 (9.2)% 3.2 %
Regulatory Required Programs. Revenue from regulatory required programs are billings for the costs of various legislative and/or regulatory programs that are recoverable from customers on a full and current basis. These programs are designed to provide full cost recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income 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, capital investments being recovered and other billing determinants. The increase in transmission revenue for the three and nine months ended September 30, 2017, compared to the same period in 2016, was primarily due to increases in capital investment and operating and maintenance expense recoveries. See Operating and Maintenance Expense below and Note 5 — 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, primarily includes late payment fees and other miscellaneous revenue such as service application fees and assistance provided to other utilities through BGE's mutual assistance program.
Operating and Maintenance Expense
 Three Months Ended  
 September 30,		 
Increase
(Decrease)
 Nine Months Ended 
 September 30,		 Increase
(Decrease)
 2017 2016  2017 2016 
Operating and maintenance expense — baseline$167
 $170
 $(3) $499
 $561
 $(62)
Operating and maintenance expense — regulatory required programs(a)
8
 8
 —
 33
 27
 6
Total operating and maintenance expense$175
 $178
 $(3) $532
 $588
 $(56)
_________
(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.

226
Table of Contents



The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:
 Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017
 Increase (Decrease) Increase (Decrease)
Baseline   
Impairment on long-lived assets and losses on regulatory assets(a)
$1
 $(50)
City of Baltimore conduit fees(4) (12)
Storm-related costs3
 (11)
Uncollectible accounts expense(8) (8)
BSC costs8
 10
Other(3) 9
 (3) (62)
Regulatory Required Programs   
Other$—
 $6
 —
 6
Total decrease$(3) $(56)
__________
(a)See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Depreciation and Amortization
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same period in 2016 consisted of the following:
 Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017
 Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$5
 $10
Regulatory asset amortization(b)
1
 25
Regulatory required programs(c)
2
 6
Total increase$8
 $41
_________
(a)Depreciation expense increased due to ongoing capital expenditures.
(b)Regulatory asset amortization increased for the three and nine months ended September 30, 2017 compared to the same period in 2016 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 and increased depreciation from AMI program capital expenditures. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(c)Depreciation and amortization expenses for regulatory required programs 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.


227
Table of Contents


Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 2017 compared to the same period in 2016 remained relatively consistent.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2017, compared to the same period in 2016 remained relatively consistent.
Effective Income Tax Rate
BGE’s effective income tax rate was 39.2% and 39.1% for the three months ended September 30, 2017 and 2016, respectively. BGE’s effective income tax rate was 39.5% and 36.3% for the nine months ended September 30, 2017 and 2016, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

228
Table of Contents


BGE Electric Operating Statistics and Revenue Detail
 Three Months Ended  
 September 30,		 % Change Weather -
Normal
% Change		 Nine Months Ended 
 September 30,		 % Change Weather -
Normal
% Change
Retail Deliveries to Customers (in GWhs)2017
2016  2017 2016 
Retail Deliveries(a)
               
Residential3,370
 3,900
 (13.6)% (2.9)% 9,126
 9,996
 (8.7)% (4.3)%
Small commercial & industrial785
 877
 (10.5)% (9.0)% 2,210
 2,343
 (5.7)% (5.8)%
Large commercial & industrial3,781
 3,992
 (5.3)% (3.9)% 10,422
 10,627
 (1.9)% (2.6)%
Public authorities & electric railroads64
 72
 (11.1)% (2.5)% 204
 215
 (5.1)% (2.5)%
Total electric deliveries8,000
 8,841
 (9.5)% (4.0)% 21,962
 23,181
 (5.3)% (3.7)%
 As of September 30,
Number of Electric Customers2017 2016
Residential1,156,659
 1,145,020
Small commercial & industrial113,224
 112,609
Large commercial & industrial12,144
 12,030
Public authorities & electric railroads274
 282
Total1,282,301
 1,269,941
 Three Months Ended  
 September 30,		 % Change Nine Months Ended 
 September 30,		 % Change
Electric Revenue2017
2016  2017 2016 
Retail Sales(a)
           
Residential$376
 $451
 (16.6)% $1,096
 $1,203
 (8.9)%
Small commercial & industrial67
 74
 (9.5)% 202
 212
 (4.7)%
Large commercial & industrial120
 123
 (2.4)% 343
 337
 1.8 %
Public authorities & electric railroads8
 9
 (11.1)% 23
 27
 (14.8)%
Total retail571

657
 (13.1)% 1,664

1,779
 (6.5)%
Other revenue(b)(c)
87
 78
 11.5 % 231
 219
 5.5 %
Total electric revenue$658

$735
 (10.5)% $1,895

$1,998
 (5.2)%
_________
(a)Reflects delivery volumes and revenue 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.
(b)Other revenue primarily includes wholesale transmission revenue and late payment charges.
(c)Includes operating revenues from affiliates totaling $1 million for both the three months ended September 30, 2017 and 2016 and $5 million for both the nine months ended September 30, 2017 and 2016.
BGE Natural Gas Operating Statistics and Revenue Detail
 Three Months Ended  
 September 30,		 % Change Weather -
Normal
% Change		 Nine Months Ended 
 September 30,		 % Change Weather -
Normal
% Change
Deliveries to Customers (in mmcf)2017 2016  2017 2016 
Retail Deliveries(a)
               
Retail sales11,221
 13,159
 (14.7)% (14.3)% 60,620
 69,415
 (12.7)% (5.3)%
Transportation and other(b)
68
 1,311
 (94.8)% n/a
 2,463
 4,078
 (39.6)% n/a
Total natural gas deliveries11,289
 14,470
 (22.0)% (14.3)% 63,083
 73,493
 (14.2)% (5.3)%

229
Table of Contents


 As of September 30,
Number of Gas Customers2017
2016
Residential626,039
 619,837
Commercial & industrial43,973
 43,957
Total670,012

663,794
 Three Months Ended  
 September 30,		 % Change Nine Months Ended 
 September 30,		 % Change
Natural Gas Revenue2017 2016  2017 2016 
Retail Sales(a)
           
Retail sales$77
 $71
 8.5 % $445
 $403
 10.4%
Transportation and other(b)
3
 6
 (50.0)% 23
 20
 15.0%
Total natural gas revenues(c)
$80
 $77
 3.9 % $468
 $423
 10.6%
_________
(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. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.
(b)Transportation and other natural gas revenue includes off-system revenue of 68 mmcfs ($1 million) and 1,311 mmcfs ($4 million) for the three months ended September 30, 2017 and 2016, respectively, and 2,463 mmcfs ($15 million) and 4,078 mmcfs ($14 million) for the nine months ended September 30, 2017 and 2016, respectively.
(c)Includes operating revenues from affiliates totaling $2 million and $6 million for the three months ended September 30, 2017 and 2016, respectively, and $7 million and $11 million for the nine months ended September 30, 2017 and 2016, respectively.

230
Table of Contents


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 20 - 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.
As a result of the PHI Merger, the following consolidated financial results present two separate reporting periods for 2016. The "Predecessor" reporting period represents PHI's results of operations for the period from January 1, 2016 to March 23, 2016. The "Successor" reporting periods represent PHI's results of operations for the three and nine months ended September 30, 2017, the three months ended September 30, 2016 and for the period from March 24, 2016 to September 30, 2016. All amounts presented below are before the impact of income taxes, except as noted.
 Successor   Successor  Predecessor
 Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, March 24 to September 30,  January 1 to March 23,
 2017 2016  2017 2016  2016
Operating revenues$1,310
 $1,394
 $(84) $3,557
 $2,565
  $1,153
Purchased power and fuel expense473
 583
 110
 1,318
 1,037
  497
Revenue net of purchased power and fuel expense(a)
837
 811
 26
 2,239
 1,528
  656
Other operating expenses            
Operating and maintenance251
 226
 (25) 774
 921
  294
Depreciation and amortization179
 182
 3
 511
 355
  152
Taxes other than income122
 124
 2
 344
 248
  105
Total other operating
expenses		552
 532
 (20) 1,629
 1,524
  551
Gain on sales of assets—
 —
 —
 1
 —
  —
Operating income285
 279
 6
 611
 4
  105
Other income and (deductions)            
Interest expense, net(62) (64) 2
 (183) (135)  (65)
Other, net13
 19
 (6) 40
 31
  (4)
Total other income and
(deductions)		(49) (45) (4) (143) (104)  (69)
Income (loss) before income taxes236
 234
 2
 468
 (100)  36
Income taxes83
 68
 (15) 109
 (9)  17
Net income (loss)$153
 $166
 $(13) $359
 $(91)  $19
_________
(a)PHI evaluates its operating performance using the measure of revenue net of purchased power and fuel expense for electric and natural gas sales. PHI believes revenue net of purchased power and fuel 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 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.
Successor Period Three Months Ended September 30, 2017 Compared to Successor Period Three Months Ended September 30, 2016
Net Income
PHI's Net income for the Successor period of three months ended September 30, 2017 was $153 million compared to $166 million for the Successor period of three months ended September 30, 2016. The decrease in Net income reflects the September 2016 pre-tax recording of a $50 million reallocation of merger-related commitments from Pepco, DPL and ACE to Exelon, which resulted in more commitments becoming obligations of Exelon. The increase in Operating

231
Table of Contents


and maintenance expense is partially offset by the impact of increases in electric distribution and natural gas rates within Revenue net of purchased power expense (Pepco electric distribution rates effective November 2016 in Maryland, Pepco electric distribution rates effective August 2017 in the District of Columbia, DPL electric distribution rates effective February 2017 in Maryland, DPL electric distribution and natural gas rates effective July 2016 and December 2016 in Delaware, and ACE electric distribution rates effective August 2016 in New Jersey).
Operating Revenue Net of Purchased Power and Fuel Expense
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $26 million for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. The increase is primarily attributable to the following factors:
Increase of $17 million at DPL primarily related to the impact of the new electric distribution and natural gas rates charged to Delaware customers that became effective in July 2016 and December 2016 and the impact of new electric distribution rates charged to Maryland customers that became effective in February 2017;
Increase of $14 million at Pepco primarily related to the impact of the new electric distribution rates charged to customers in Maryland that became effective in November 2016 and and the impact of new electric distribution rates charged to customers in the District of Columbia effective August 2017; and
Decrease of $6 million at ACE primarily related to lower average customer usage and unfavorable weather related sales, partially offset by the impact of the new electric distribution base rate charged to customers that became effective in August 2016.
Operating and Maintenance Expense
Operating and maintenance expense increased by $25 million for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. The increase is attributable to the following factors:
Increase of $24 million at DPL due primarily to a merger commitment reallocation from DPL to Exelon that decreased Operating and maintenance expense in 2016;
Increase of $5 million at ACE primarily due to a merger commitment reallocation from ACE to Exelon that decreased Operating and maintenance expense in 2016, partially offset by the deferral of merger-related costs to a regulatory asset; and
Decrease of $6 million at Pepco primarily due to the deferral of merger-related, rate case, and customer billing system costs to a regulatory asset, partially offset by a merger commitment reallocation from Pepco to Exelon that decreased Operating and maintenance expense in 2016.
Depreciation and Amortization Expense
Depreciation and amortization expense decreased by $3 million primarily due to lower amortization expense at ACE resulting from lower revenue due to rate decreases effective October 2016 for the ACE Transition Bond Charge and ACE Market Transition Charge Tax, partially offset by higher depreciation as a result of higher Maryland depreciation rates at Pepco effective November 2016 and at DPL effective February 2017 and due to ongoing capital expenditures at Pepco, DPL, and ACE.
Taxes Other Than Income
Taxes other than income decreased by $2 million primarily due to lower utility taxes that are collected and passed through by Pepco, partially offset by higher property taxes at Pepco.
Interest Expense, Net
Interest expense decreased by $2 million primarily due to the redemption of long-term debt in December 2016 and lower short-term debt interest rates.

232
Table of Contents


Other, Net
Other, net decreased by $6 million primarily due to the September 2016 reversal of contributions in aid of construction tax gross-up reserves due to the determination that there is no legal obligation to refund customers per contract terms.
Effective Income Tax Rate
PHI's effective income tax rate was 35.2% and 29.1% for the three months ended September 30, 2017 and 2016, respectively. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Successor Period Nine Months Ended September 30, 2017
PHI's Net income for the Successor period of nine months ended September 30, 2017 was $359 million. Therewere no significant changes in the underlying trends affecting PHI's operations during the Successor period of nine months ended September 30, 2017 except for the impact of increases in electric distribution and natural gas rates within Revenue net of purchased power expense (Pepco electric distribution rates effective November 2016 in Maryland, Pepco electric distribution rates effective August 2017 in the District of Columbia, DPL electric distribution rates effective February 2017 in Maryland, DPL electric distribution and natural gas rates effective July 2016 and December 2016 in Delaware, and ACE electric distribution rates effective August 2016 in New Jersey). The deferral of merger-related, rate case, and customer billing system costs to a regulatory asset and lower uncollectible accounts expense contributed to lower Operating and maintenance expense. Income taxes were lower due to unrecognized tax benefits of $59 million for uncertain tax positions related to the deductibility of certain merger commitments in the first quarter of 2017.
PHI's effective income tax rate for the Successor period of nine months ended September 30, 2017 was 23.3%. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Successor Period March 24, 2016 to September 30, 2016
PHI's Net loss for the Successor period from March 24, 2016 to September 30, 2016was $91 million. Therewere no significant changes in the underlying trends affecting PHI's results of operations during the Successor period of March 24, 2016 to September 30, 2016 except for the pre-tax recording of $375 million of non-recurring merger-related costs within Operating and maintenance expense.
PHI's effective income tax rate for the Successor period of March 24, 2016 to September 30, 2016 was 9.0%. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Predecessor Period January 1, 2016 to March 23, 2016
PHI's Net income for the Predecessor period of January 1, 2016 to March 23, 2016was $19 million. Therewere 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 Predecessor period of January 1, 2016 to March 23, 2016 was 47.2%. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

233
Table of Contents


Results of Operations - Pepco
 Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2017 2016  2017 2016 
Operating revenues$604
 $635
 $(31) $1,649
 $1,695
 $(46)
Purchased power expense168
 213
 45
 478
 563
 85
Revenue net of purchased power expense(a)
436
 422
 14
 1,171
 1,132
 39
Other operating expenses           
Operating and maintenance103
 109
 6
 336
 508
 172
Depreciation and amortization82
 76
 (6) 242
 221
 (21)
Taxes other than income102
 105
 3
 282
 287
 5
Total other operating expenses287
 290
 3
 860
 1,016
 156
Gain on sales of assets—
 —
 —
 1
 8
 (7)
Operating income149
 132
 17
 312
 124
 188
Other income and (deductions)    
     
Interest expense, net(31) (30) (1) (89) (98) 9
Other, net7
 12
 (5) 22
 28
 (6)
Total other income and (deductions)(24) (18) (6) (67) (70) 3
Income before income taxes125
 114
 11
 245
 54
 191
Income taxes38
 35
 (3) 57
 34
 (23)
Net income$87
 $79
 $8
 $188
 $20
 $168
_________
(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
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016. 2017. ComEd’s Net income for the three months ended September 30, 2018 was higher than the same period in 2017 primarily due to higher electric distribution and energy efficiency formula rate earnings. The TCJA did not significantly impact ComEd's net income for the three months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017. ComEd’s Net income for the nine months ended September 30, 2018 was higher than the same period in 2017 primarily due to higher electric distribution and energy efficiency formula rate earnings as well as additional tax and interest recorded in the second quarter of 2017 relating to Exelon's like-kind exchange tax position. The TCJA did not significantly impact ComEd's net income for the nine

Table of Contents

months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Revenues Net of Purchased Power Expense
There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC, and ZEC procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity, REC, and ZEC procurement costs from retail customers without mark-up. Therefore, fluctuations in these costs have no impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Exelon 2017 Form 10-K 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 three and nine months ended September 30, 2018 and 2017, consisted of the following:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric67% 68% 68% 70%
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2018 and 2017 consisted of the following:
 September 30, 2018 September 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric1,367,700
 34% 1,360,800
 34%
The changes in ComEd’s Revenue net of purchased power expense for the three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Electric distribution revenue$(59) $(126)
Transmission revenue(16) (32)
Energy efficiency revenue(a)
14
 31
Regulatory required programs(a)
(1) (95)
Uncollectible accounts recovery, net2
 5
Other(3) 37
Total decrease$(63) $(180)
_________
(a)Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

Table of Contents

Revenue Decoupling. The demand for electricity is affected by weather conditions. Under FEJA, ComEd revised its electric distribution rate formula effective January 1, 2017 to eliminate the favorable and unfavorable impacts on Operating revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage 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 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 three and nine months ended September 30, 2018 and 2017, consisted of the following:
Heating and Cooling Degree-Days      % Change
Three Months Ended September 30,2018 2017 Normal2018 vs. 2017 2018 vs. Normal
Heating Degree-Days56
 42
 97
 33.3% (42.3)%
Cooling Degree-Days895
 699
 641
 28.0% 39.6 %
          
Nine Months Ended September 30,         
Heating Degree-Days3,993
 3,269
 3,972
 22.1% 0.5 %
Cooling Degree-Days1,259
 962
 882
 30.9% 42.7 %
Electric Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. 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. Electric distribution revenue decreased during the three and nine months ended September 30, 2018, primarily due to the impact of the lower federal income tax rate, partially offset by increased revenues due to higher rate base and increased depreciation expense as compared to the same period in 2017. See Depreciation and amortization expense discussions below and Note 6 — Regulatory Matters and Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. For the three months ended September 30, 2018, ComEd recorded decreased transmission revenue primarily due to the impact of the lower federal income tax rate, partially offset by increased revenues due to higher rate base and increased depreciation expense as compared to the same period in 2017. For the nine months ended September 30, 2018, ComEd recorded decreased transmission revenue primarily due to the decreased peak load and the impact of the lower federal income tax rate, partially offset by increased revenues due to higher rate base and increased depreciation expense as compared to the same period in 2017. See Operating and maintenance expense below and Note 6 — Regulatory Matters and Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue. Beginning June 1, 2017, FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual

Table of Contents

costs that the ICC determines are prudently and reasonably incurred in a given year.  Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE 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. See Depreciation and amortization expense discussions below and Note 6 — 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 rate riders to recover costs incurred for regulatory programs such as ComEd’s purchased power administrative costs and energy efficiency and demand response through June 1, 2017 pursuant to FEJA. The riders are designed to provide full and current cost recovery. 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.
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. The increase in Other revenue for the nine months ended September 30, 2018 compared to the same period in 2017 primarily reflects mutual assistance revenues associated with hurricane and winter storm restoration efforts. An equal and offsetting amount has been included in Operating and maintenance expense and Taxes other than income.
Operating and Maintenance Expense
 Three Months Ended
September 30,		 
Increase
(Decrease)
 Nine Months Ended
September 30,		 Increase (Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense — baseline$336
 $344
 $(8) $973
 $1,000
 $(27)
Operating and maintenance expense — regulatory required programs(a)
1
 2
 $(1) 1
 96
 (95)
Total Operating and maintenance expense$337

$346

$(9)
$974

$1,096

$(122)
_________
(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.

Table of Contents

The decrease in Operating and maintenance expense for the three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor, other benefits, contracting and materials(a)
$(1) $(3)
Pension and non-pension postretirement benefits expense(a)
(1) (1)
Storm-related costs(5) (21)
Uncollectible accounts expense — provision(b)
7
 11
Uncollectible accounts expense — recovery, net(b)
(5) (6)
BSC costs(a)
(9) (8)
Other(a)
6
 1
 (8) (27)
Regulatory required programs   
Energy efficiency and demand response programs(c)
(1) (95)
Decrease in operating and maintenance expense$(9) $(122)
_________
(a)Includes additional costs associated with mutual assistance programs. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
(b)ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. During the three and nine months ended September 30, 2018, ComEd recorded a net increase in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
(c)Beginning June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.
Depreciation and Amortization Expense
The increase in Depreciation and amortization expense during the three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase Increase
Depreciation expense(a)
$9
 $30
Regulatory asset amortization(b)
16
 35
Total increase$25
 $65
_________
(a)Primarily reflects ongoing capital expenditures for the three and nine months ended September 30, 2018.
(b)Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset.
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.

Table of Contents

Gain on Sales of Assets
The increase in Gain on sales of assets during the nine months ended September 30, 2018 compared to the same period in 2017, is primarily due to the sale of land in March 2018.
Interest Expense, Net
The changes in Interest expense, net, for the three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Interest expense related to uncertain tax positions(a)
$—
 $(13)
Interest expense on debt (including financing trusts)(2) 2
Other(2) (3)
Total decrease$(4) $(14)
__________
(a)Primarily reflects additional interest recorded in the second quarter of 2017 related to Exelon's like-kind exchange tax position.
Other, Net
Other, net, remained relatively consistent for the three and nine months ended September 30, 2018 compared to the same period in 2017.
Effective Income Tax Rate
ComEd's effective income tax rate was 21.2% and 40.9% for the three months ended September 30, 2018 and 2017, respectively. ComEd's effective income tax rate was 21.1% and 42.3% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

ComEd Electric Operating Statistics Detail
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		 % Change 
Weather-
Normal
% Change
 Nine Months Ended
September 30,		 % Change 
Weather-
Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential8,845
 8,004
 10.5 % (1.5)% 22,019
 20,164
 9.2% 0.1%
Small commercial & industrial8,626
 8,488
 1.6 % (1.0)% 24,204
 23,634
 2.4% —%
Large commercial & industrial7,450
 7,232
 3.0 % 1.1 % 21,398
 20,712
 3.3% 1.6%
Public authorities & electric railroads301
 302
 (0.3)% (0.5)% 947
 928
 2.0% 1.2%
Total retail deliveries25,222

24,026
 5.0 % (0.5)% 68,568

65,438
 4.8% 0.6%
 As of September 30,
Number of Electric Customers2018 2017
Residential3,635,678
 3,610,091
Small commercial & industrial380,529
 376,309
Large commercial & industrial1,994
 1,954
Public authorities & electric railroads4,767
 4,763
Total4,022,968

3,993,117
_________
(a)Reflects delivery 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.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

Table of Contents

Results of Operations — PECO
 Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$757
 $715
 $42
 $2,275
 $2,141
 $134
Purchased power and fuel expense263
 235
 (28) 818
 719
 (99)
Revenues net of purchased power and fuel expense(a)
494
 480
 14
 1,457
 1,422
 35
Other operating expenses           
Operating and maintenance219
 197
 (22) 686
 595
 (91)
Depreciation and amortization75
 72
 (3) 224
 213
 (11)
Taxes other than income46
 42
 (4) 125
 116
 (9)
Total other operating expenses340
 311
 (29) 1,035
 924
 (111)
Gain on sales of assets—
 —
 —
 1
 —
 1
Operating income154
 169
 (15) 423
 498
 (75)
Other income and (deductions)           
Interest expense, net(32) (31) (1) (96) (93) (3)
Other, net2
 2
 —
 4
 6
 (2)
Total other income and (deductions)(30) (29) (1) (92) (87) (5)
Income before income taxes124
 140
 (16) 331
 411
 (80)
Income taxes(2) 28
 30
 (5) 84
 89
Net income$126
 $112
 $14
 $336
 $327
 $9
_________
(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 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 presentations 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
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017.PECO's Net income increased from the same period in 2017, primarily due to higher Operating revenues net of purchase power and fuel expense attributable to favorable weather and volume. The TCJA did not significantly impact PECO's Net income for the three and nine months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the requirement to pass back the tax savings through customer rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.PECO's Net income increased from the same period in 2017, primarily due to higher Operating revenues net of purchase power and fuel expense attributable to favorable weather and volume, partially offset by higher Operating and maintenance expense attributable to increased storm restoration costs as a result of winter storms in March 2018. The TCJA did not significantly impact PECO's Net income for the three and nine months ended September 30, 2018 as the favorable income tax impacts were

Table of Contents

predominantly offset by lower revenues resulting from the requirement to pass back the tax savings through customer rates.
Revenues Net of Purchased Power and Fuel Expense
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 revenue 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 revenues net of purchased 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 three and nine months ended September 30, 2018 and 2017, consisted of the following:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric68% 70% 69% 71%
Natural Gas31% 29% 26% 26%
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2018 and 2017 consisted of the following:
 September 30, 2018 September 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric536,000
 33% 570,500
 35%
Natural Gas88,900
 17% 82,600
 16%

Table of Contents

The changes in PECO’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
 Electric Natural Gas Total Electric Natural Gas Total
Weather$20
 $1
 $21
 $39
 $19
 $58
Volume17
 (1) 16
 26
 2
 28
Pricing(36) 3
 (33) (66) (5) (71)
Regulatory required programs7
 —
 7
 5
 —
 5
Other3
 —
 3
 18
 (3) 15
Total increase$11
 $3
 $14
 $22
 $13
 $35
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2018 compared to the same period in 2017, Operating revenue net of purchased power and fuel increased due to favorable weather conditions.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and nine months ended September 30, 2018 compared to the same period in 2017 and normal weather consisted of the following:
Heating and Cooling Degree-Days  Normal % Change
Three Months Ended September 30,2018 2017From 2017 2018 vs. Normal
Heating Degree-Days13
 14
 27
 (7.1)% (51.9)%
Cooling Degree-Days1,124
 989
 999
 13.7 % 12.5 %
          
Nine Months Ended September 30,         
Heating Degree-Days2,892
 2,437
 2,912
 18.7 % (0.7)%
Cooling Degree-Days1,506
 1,404
 1,383
 7.3 % 8.9 %
Volume. Operating revenue net of purchased power related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2018 compared to the same period in 2017, increased due to the impact of moderate economic and customer growth partially offset by the impact of energy efficiency initiatives on customer usages primarily in the residential class. Additionally, the increase represents a shift in the volume profile across classes from the commercial and industrial classes to the residential class.
Pricing.Operating revenues net of purchased power as a result of pricing for the three and nine months ended September 30, 2018 and operating revenues net of fuel as the result of pricing for the nine months ended September 30, 2018 compared to the same periods in 2017 decreased primarily due to the pass back through customers rates the tax savings associated with the lower federal income

Table of Contents

tax rate. See Note 6 — 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 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. See 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
 Three Months Ended
September 30,		 
Increase
(Decrease)
 Nine Months Ended
September 30,		 Increase
(Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense — baseline$198
 $183
 $15
 $632
 $552
 $80
Operating and maintenance expense — regulatory required programs(a)
21
 14
 7
 54
 43
 11
Total Operating and maintenance expense$219
 $197
 $22
 $686
 $595
 $91
_________
(a)Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
The changes in Operating and maintenance expense for the three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor, other benefits, contracting and materials$(1) $10
Storm-related costs(a)
2
 61
Pension and non-pension postretirement benefits expense(2) (5)
Uncollectible accounts expense6
 8
Other10
 6
 15
 80
Regulatory Required Programs   
Energy efficiency7
 11
Total increase$22
 $91
__________
(a)Reflects increased costs incurred from the Q1 2018 winter storms.

Table of Contents

Depreciation and Amortization Expense
Depreciation and amortization expense increased primarily due to ongoing capital spend for the three and nine months ended September 30, 2018 compared to the same period in 2017.
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income increased for the three and nine months ended September 30, 2018 compared to the same period in 2017 due to an increase in gross receipts tax driven by an increase in electric revenue.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2018 remained relatively consistent compared to the same period in 2017.
Other, Net
Other, net for the three and nine months ended September 30, 2018 remained consistent compared to the same period in 2017.
Effective Income Tax Rate
PECO's effective income tax rate was (1.6)% and 20.0% for the three months ended September 30, 2018 and 2017, respectively. PECO's effective income tax rate was (1.5)% and 20.4% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

PECO Electric Operating Statistics
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		 % Change 
Weather -
Normal
% Change
 Nine Months Ended
September 30,		 % Change Weather -
Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential4,166
 3,752
 11.0 % 4.7 % 10,741
 9,939
 8.1 % 2.8 %
Small commercial & industrial2,315
 2,158
 7.3 % 2.0 % 6,273
 6,048
 3.7 % 0.4 %
Large commercial & industrial4,378
 4,137
 5.8 % 4.9 % 11,892
 11,593
 2.6 % 2.5 %
Public authorities & electric railroads189
 198
 (4.5)% (4.8)% 568
 618
 (8.1)% (7.7)%
Total retail deliveries11,048

10,245
 7.8 % 4.0 % 29,474

28,198
 4.5 % 1.9 %
 As of September 30,
Number of Electric Customers2018 2017
Residential1,476,914
 1,463,906
Small commercial & industrial152,253
 150,964
Large commercial & industrial3,124
 3,112
Public authorities & electric railroads9,561
 9,665
Total1,641,852
 1,627,647
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

Table of Contents

PECO Natural Gas Operating Statistics
Deliveries to Customers (in mmcf)Three Months Ended
September 30,		 % Change 
Weather -
 Normal
% Change
 Nine Months Ended
September 30,		 % Change 
Weather -
 Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential2,099
 2,177
 (3.6)% 0.9% 28,562
 24,866
 14.9% 0.2 %
Small commercial & industrial1,776
 1,814
 (2.1)% 0.2% 15,792
 13,944
 13.3% 1.0 %
Large commercial & industrial6
 2
 200.0 % 12.8% 58
 15
 286.7% 278.3 %
Transportation5,693
 5,674
 0.3 % 3.2% 19,242
 19,122
 0.6% (3.8)%
Total natural gas deliveries9,574
 9,667
 (1.0)% 1.6% 63,654
 57,947
 9.8% (0.8)%
 As of September 30,
Number of Natural Gas Customers2018 2017
Residential479,732
 474,766
Small commercial & industrial43,638
 43,352
Large commercial & industrial1
 6
Transportation761
 771
Total524,132

518,895
_________
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

Table of Contents

Results of Operations — BGE
 Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$731
 $738
 $(7) $2,369
 $2,363
 $6
Purchased power and fuel expense272
 269
 (3) 881
 853
 (28)
Revenues net of purchased power and fuel expense(a)
459
 469
 (10) 1,488
 1,510
 (22)
Other operating expenses           
Operating and maintenance182
 175
 (7) 578
 532
 (46)
Depreciation and amortization110
 109
 (1) 358
 348
 (10)
Taxes other than income64
 61
 (3) 188
 180
 (8)
Total other operating expenses356
 345
 (11) 1,124
 1,060
 (64)
Gain on sales of assets—
 —
 —
 1
 —
 1
Operating income103
 124
 (21) 365
 450
 (85)
Other income and (deductions)           
Interest expense, net(27) (26) (1) (78) (80) 2
Other, net5
 4
 1
 14
 12
 2
Total other income and (deductions)(22) (22) —
 (64) (68) 4
Income before income taxes81
 102
 (21) 301
 382
 (81)
Income taxes18
 40
 22
 59
 151
 92
Net income$63
 $62
 $1
 $242
 $231
 $11
_________
(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
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017. BGE’s Net income for the three months ended September 30, 2018 was relatively consistent with the same period in 2017. The TCJA did not significantly impact BGE's net income for the three months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017. BGE’s Net income for the nine months ended September 30, 2018 was higher than the same period in 2017, due primarily to higher transmission revenues, partially offset by an increase in Operating and maintenance expense attributable to increased storm restoration costs as a result of storms in March 2018 and September 2018. The TCJA did not significantly impact BGE's net income for the nine months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.

Table of Contents

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. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on 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 the number of customers electing to use a competitive supplier for electricity and/or natural gas. All BGE customers have the choice to purchase electricity and natural gas from competitive suppliers. The customers' choice of suppliers does not impact the volume of deliveries but does affect revenue collected from customers related to supplied electricity and natural gas.
Retail deliveries purchased from competitive electricity and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30, 2018 and 2017 consisted of the following:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric59% 60% 59% 60%
Natural Gas76% 74% 56% 57%
The number of retail customers purchasing electricity and natural gas from competitive suppliers at September 30, 2018 and 2017 consisted of the following:
 September 30, 2018 September 30, 2017
 Number of Customers % of total retail customers Number of customers % of total retail customers
Electric335,200
 26% 339,300
 27%
Natural Gas147,400
 22% 148,600
 22%

Table of Contents

The changes in BGE’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2018, compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
 Electric Gas Total Electric Gas Total
Distribution revenue$(17) $(2) $(19) $(48) $(19) $(67)
Regulatory required programs1
 (1) —
 3
 2
 5
Transmission revenue6
 —
 6
 23
 —
 23
Other, net—
 3
 3
 6
 11
 17
Total decrease$(10) $—
 $(10) $(16) $(6) $(22)
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 fluctuations in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved distribution charges 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 volatility in 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 three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
Heating and Cooling Degree-Days      % Change
Three Months Ended September 30,2018 2017 Normal 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days31
 64
 76
 (51.6)% (59.2)%
Cooling Degree-Days733
 595
 601
 23.2 % 22.0 %
          
Nine Months Ended September 30,         
Heating Degree-Days2,969
 2,524
 2,974
 17.6 % (0.2)%
Cooling Degree-Days1,032
 877
 857
 17.7 % 20.4 %
Distribution Revenue. The decrease in distribution revenues for the three and nine months ended September 30, 2018, compared to the same period in 2017, was primarily due to the impact of reduced distribution rates to reflect the lower federal income tax rate. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Table of Contents

Regulatory Required Programs. Revenue from regulatory required programs are billings for the costs of various legislative and/or regulatory programs that are recoverable from customers on a full and current basis. These programs are designed to provide full cost recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income 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 rate adjustments to reflect fluctuations in the underlying costs, capital investments being recovered and other billing determinants. The increase in transmission revenue for the three and nine months ended September 30, 2018, compared to the same period in 2017, was primarily due to increases in capital investment and operating and maintenance expense recoveries. See Operating and Maintenance Expense below and Note 6 — 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, primarily includes assistance provided to other utilities through BGE's mutual assistance program, service application fees, and other miscellaneous revenue such as off-system sales and administrative charges.
Operating and Maintenance Expense
 Three Months Ended
September 30,		 
Increase
(Decrease)
 Nine Months Ended
September 30,		 Increase
(Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense — baseline$180
 $172
 $8
 $572
 $520
 $52
Operating and maintenance expense — regulatory required programs(a)
2
 3
 (1) 6
 12
 (6)
Total Operating and maintenance expense$182
 $175
 $7
 $578
 $532
 $46
_________
(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.

Table of Contents

The changes in Operating and maintenance expense for the three and nine months ended September 30, 2018, compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Storm-related costs(a)
$5
 $36
Labor, other benefits, contracting and materials1
 2
Uncollectible accounts expense1
 3
BSC costs(1) 4
Other2
 7
 8
 52
Regulatory Required Programs   
Other(1) (6)
Total increase$7
 $46
__________
(a)Reflects increased storm restoration costs incurred from storms in Q1 2018 and Q3 2018.
Depreciation and Amortization
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2018, compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$8
 $17
Regulatory asset amortization(b)
(8) (18)
Regulatory required programs(c)
1
 11
Total increase$1
 $10
_________
(a)Depreciation expense increased due to ongoing capital expenditures.
(b)Regulatory asset amortization decreased for the three and nine months ended September 30, 2018 compared to the same period in 2017 primarily due to certain regulatory assets that became fully amortized as of December 31, 2017. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(c)Depreciation and amortization expenses for regulatory required programs 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.
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 2018, compared to the same period in 2017, increased primarily due to an increase in property taxes.
Gain on Sales of Assets
Gain on sales of assets, for the three months ended September 30, 2018 compared to the same period in 2017, remained relatively consistent. The increase in Gain on sales of assets during the nine

Table of Contents

months ended September 30, 2018, compared to the same period in 2017, is due to the sale of land in June 2018.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2018, compared to the same period in 2017, remained relatively consistent.
Other, Net
Other, net for the three and nine months ended September 30, 2018, compared to the same period in 2017, remained relatively consistent.
Effective Income Tax Rate
BGE’s effective income tax rate was 22.2% and 39.2% for the three months ended September 30, 2018 and 2017, respectively. BGE's effective income tax rate was 19.6% and 39.5% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and nine months ended September 30, 2018, compared to the same periods in 2017, is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — 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 Detail
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		 % Change Weather -
Normal
% Change		 Nine Months Ended
September 30,		 % Change Weather -
Normal
% Change
2018
2017  2018 2017 
Retail Deliveries(a)
               
Residential3,663
 3,370
 8.7% 1.8 % 9,960
 9,126
 9.1 % 1.8 %
Small commercial & industrial825
 785
 5.1% (1.1)% 2,309
 2,210
 4.5 % (0.2)%
Large commercial & industrial3,909
 3,781
 3.4% 0.6 % 10,661
 10,422
 2.3 % (0.1)%
Public authorities & electric railroads64
 64
 —% (5.9)% 200
 204
 (2.0)% (4.1)%
Total electric deliveries8,461
 8,000
 5.8% 0.9 % 23,130
 21,962
 5.3 % 0.7 %
 As of September 30,
Number of Electric Customers2018 2017
Residential1,165,012
 1,156,659
Small commercial & industrial114,082
 113,224
Large commercial & industrial12,218
 12,144
Public authorities & electric railroads263
 274
Total1,291,575
 1,282,301
_________
(a)Reflects delivery 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.

Table of Contents

BGE Natural Gas Operating Statistics and Detail
Deliveries to Customers (in mmcf)Three Months Ended
September 30,		 % Change Weather -
Normal
% Change		 Nine Months Ended
September 30,		 % Change Weather -
Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential2,244
 2,395
 (6.3)% (4.5)% 29,290
 24,125
 21.4% 3.2%
Small commercial & industrial813
 814
 (0.1)% 0.4 % 7,020
 5,667
 23.9% 7.2%
Large commercial & industrial8,227
 8,012
 2.7 % 2.2 % 34,044
 30,828
 10.4% 5.9%
Other(b)
3,144
 68
 4,523.5 % n/a
 11,183
 2,463
 354.0% n/a
Total natural gas deliveries14,428
 11,289
 27.8 % 0.6 % 81,537
 63,083
 29.3% 4.9%
 As of September 30,
Number of Gas Customers2018
2017
Residential631,589
 626,039
Small commercial & industrial38,175
 38,141
Large commercial & industrial5,920
 5,832
Total675,684

670,012
_________
(a)Reflects delivery volumes 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.
(b)Other natural gas revenue includes off-system sales of 3,144 mmcfs and 68 mmcfs for the three months ended September 30, 2018 and 2017, respectively. Other natural gas revenue includes off-system sales of 11,183 mmcfs and 2,463 mmcfs for the nine months ended September 30, 2018 and 2017. respectively.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

Table of Contents

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. 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.
 Three Months Ended
September 30,		 Favorable (Unfavorable) Variance Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$1,361
 $1,310
 $51
 $3,688
 $3,557
 $131
Purchased power and fuel expense509
 473
 (36) 1,410
 1,318
 (92)
Revenues net of purchased power and fuel expense(a)
852
 837
 15
 2,278
 2,239
 39
Other operating expenses           
Operating and maintenance292
 251
 (41) 857
 774
 (83)
Depreciation and amortization192
 179
 (13) 555
 511
 (44)
Taxes other than income123
 122
 (1) 343
 344
 1
Total other operating expenses607
 552
 (55) 1,755
 1,629
 (126)
Gain on sales of assets—
 —
 —
 —
 1
 (1)
Operating income245
 285
 (40) 523
 611
 (88)
Other income and (deductions)           
Interest expense, net(65) (62) (3) (193) (183) (10)
Other, net11
 13
 (2) 33
 40
 (7)
Total other income and (deductions)(54) (49) (5) (160) (143) (17)
Income before income taxes191
 236
 (45) 363
 468
 (105)
Income taxes4
 83
 79
 28
 109
 81
Equity in earnings of unconsolidated affiliate—
 —
 —
 1
 —
 1
Net income$187
 $153
 $34
 $336
 $359
 $(23)
_________
(a)PHI evaluates its operating performance using the measure of revenue net of purchased power and fuel expense for electric and natural gas sales. PHI believes revenue net of purchased power and fuel 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 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.
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017.PHI's Net income for the three months ended September 30, 2018 was $187 million compared to $153 million for the three months ended September 30, 2017.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $15 million for the three months ended September 30, 2018 compared to the same period in 2017 primarily due to higher utility revenues due to distribution rate increases at Pepco, DPL, and ACE, as well as favorable weather and volume, partially offset by lower revenues resulting from the pass back of TCJA tax savings through customer rates.

Table of Contents

Operating and maintenance expense increased by $41 million for the three months ended September 30, 2018 compared to the same period in 2017. The increase is primarily due to the following factors:
Increase of $22 million at Pepco due to a charge associated with a remeasurement of the Buzzard Point ARO; and
Increase of $14 million primarily due to deferral of accumulated merger integration costs as regulatory assets in 2017.
Depreciation and amortization expense for the three months ended September 30, 2018 compared to the same period in 2017 increased by $13 million primarily due to ongoing capital expenditures as well as increased amortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues).
Taxes other than income for the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Gain on sales of assets during the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Interest expense, net for the three months ended September 30, 2018 compared to the same period in 2017 increased by $3 million due to higher outstanding debt.
Other, net for the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Equity in earnings for the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
PHI's effective income tax rate was 2.1% and 35.2% for the three months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.PHI's Net income for the nine months ended September 30, 2018 was $336 million compared to $359 million for the nine months ended September 30, 2017.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $39 million for the nine months ended September 30, 2018 compared to the same period in 2017 primarily due to higher utility revenues due to distribution rate increases at Pepco, DPL, and ACE, as well as favorable weather and volume, partially offset by lower revenues resulting from the pass back of TCJA tax savings through customer rates.

Table of Contents

Operating and maintenance expense increased by $83 million for the nine months ended September 30, 2018 compared to the same period in 2017. The increase is primarily due to the following factors:
Increase of $28 million primarily due to deferral of accumulated merger integration costs as regulatory assets in 2017;
Net increase of $23 million in labor and contracting expense due to an increase of $32 million at Pepco, DPL and ACE partially offset by a decrease of $9 million at PHISCO as a result of the completion of integration transition activities; and
Increase of $22 million at Pepco due to a charge associated with a remeasurement of the Buzzard Point ARO.
Depreciation and amortization expense for the nine months ended September 30, 2018 compared to the same period in 2017 increased by $44 million primarily due to ongoing capital expenditures as well as increased amortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues).
Taxes other than income for the nine months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Gain on sales of assets during the nine months ended September 30, 2018 compared to the same period in 2017 decreased $1 million due to the sale of land in June 2017.
Interest expense, net for the nine months ended September 30, 2018 compared to the same period in 2017 increased $10 million due to higher outstanding debt.
Other, net for the nine months ended September 30, 2018 compared to the same period in 2017 decreased $7 million primarily due to lower income from AFUDC equity.
Equity in earnings for the nine months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
PHI's effective income tax rate was 7.7% and 23.3% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA, partially offset by a nonrecurring adjustment to income tax reserve balances in 2017. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

Results of Operations - Pepco
 Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2018 2017  2018 2017 
Operating revenues$628
 $604
 $24
 $1,708
 $1,649
 $59
Purchased power expense177
 168
 (9) 497
 478
 (19)
Revenues net of purchased power expense(a)
451
 436
 15
 1,211
 1,171
 40
Other operating expenses           
Operating and maintenance136
 103
 (33) 383
 336
 (47)
Depreciation and amortization99
 82
 (17) 286
 242
 (44)
Taxes other than income104
 102
 (2) 288
 282
 (6)
Total other operating expenses339
 287
 (52) 957
 860
 (97)
Gain on sales of assets—
 —
 —
 —
 1
 (1)
Operating income112
 149
 (37) 254
 312
 (58)
Other income and (deductions)    
     
Interest expense, net(32) (31) (1) (96) (89) (7)
Other, net7
 7
 —
 23
 22
 1
Total other income and (deductions)(25) (24) (1) (73) (67) (6)
Income before income taxes87
 125
 (38) 181
 245
 (64)
Income taxes(2) 38
 40
 7
 57
 50
Net income$89
 $87
 $2
 $174
 $188
 $(14)
_________
(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
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017.Pepco's Net income for the three months ended September 30, 2017,2018, was higher thanrelatively consistent with the same period in 2016, primarily due to an increase in Revenue net of purchased power expense2017. The TCJA did not significantly impact Pepco's Net income for the three months ended September 30, 2018 as the favorable tax impacts were predominantly offset by lower revenues resulting from higher electric distribution revenues as a resultthe pass back of the distribution rate increase approved by the MDPSC effective November 2016 and the distribution rate increase approved by the DCPSC effective August 2017.tax savings through customer rates.
Nine Months Ended September 30, 20172018 Compared to Nine Months Ended September 30, 2016. 2017.Pepco's Net income for the nine months ended September 30, 2017,2018, was higherlower than the same period in 2016,2017 primarily due to higher Operating and maintenance expense attributable to an increase in Revenue net of purchased power expense resulting from higher electric distribution revenues as a result of the distribution rate increase approved by the MDPSC effective November 2016 and the distribution rate increase approved by the DCPSC effective August 2017, lower Operating and maintenance expense due to merger-related costs recognized in March 2016, and a decrease in income tax reserves in the first quarter of 2017 for uncertain tax positionsasset retirement obligations related to the deductibilityBuzzard Point property, deferral of certainaccumulated merger commitments,integration costs as regulatory assets in 2017 and higher regulatory asset amortization due to additional regulatory assets related to rate case activity, partially offset by higher depreciation expense dueelectric distribution base rates charged to increased depreciation ratescustomers in Maryland that became effective November 2016.in October 2017 and June 2018 and higher electric distribution base rates charged to customers in the District of Columbia that became effective August 2017 and August 2018. The TCJA did not significantly impact Pepco's Net income for the nine
Operating Revenue

Table of Contents

months ended September 30, 2018 as the favorable tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
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. 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.
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

234
Table of Contents


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 three and nine months ended September 30, 2017,2018 compared to the same periodsperiod in 2016,2017, consisted of the following:
 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
Electric65% 63% 66% 65%
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric64% 65% 64% 66%
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 20172018 and 20162017 consisted of the following:
 September 30, 2017 September 30, 2016
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric179,106
 21% 175,960
 21%
 September 30, 2018 September 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric175,838
 20% 179,106
 21%
Retail deliveries purchased from competitive electric generation suppliers represented 72% and 72% of Pepco’s retail kWh sales to the District of Columbia customers and 58% and 58% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2018, respectively and 72% and 73% of Pepco’s retail kWh sales to the District of Columbia customers and 60% and 60% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2017, respectively and 71% and 72%respectively.

Table of Pepco’s retail kWh sales to the District of Columbia customers and 58% and 59% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2016, respectively.Contents
Operating revenues 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 three and nine months ended September 30, 20172018 compared to the same periods in 20162017 consisted of the following:
 Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
 Increase (Decrease) Increase (Decrease)
Volume$5
 $13
Distribution rate increase17
 45
Regulatory required programs(6) (11)
Transmission revenues3
 9
Other(5) (17)
Total increase$14
 $39
Volume. The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2017 compared to the same periods in 2016, primarily reflects the impact of customer growth.
Distribution Rate Increase. The increase in electric operating revenues net of purchased power expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 was primarily due to the

235
Table of Contents


impact of higher electric distribution rates charged to customers in Maryland that became effective in November 2016 and higher electric distribution rates charged to customers in the District of Columbia that became effective August 2017. See Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
 Increase (Decrease) Increase (Decrease)
Volume$3
 $9
Distribution revenue6
 9
Regulatory required programs7
 27
Transmission revenue2
 (5)
Other(3) —
Total increase$15
 $40
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 daysdegree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree daysdegree-days for a 20-year period in Pepco's service territory. The changes in heating and cooling degree daysdegree-days in Pepco’s service territory for the three and nine months ended September 30, 20172018 compared to the same periods in 20162017 and normal weather consisted of the following:
    % Change
2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating and Cooling Degree-Days    % Change
Three Months Ended September 30,         2018 2017 Normal 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days8
 1
 19
 700.0 % (57.9)%2
 8
 13
 (75.0)% (84.6)%
Cooling Degree-Days1,130
 1,418
 1,133
 (20.3)% (0.3)%1,283
 1,130
 1,137
 13.5 % 12.8 %
      

 

      

 

Nine Months Ended September 30,      

 

      

 

Heating Degree-Days1,963
 2,408
 2,477
 (18.5)% (20.8)%2,458
 1,963
 2,448
 25.2 % 0.4 %
Cooling Degree-Days1,679
 1,872
 1,611
 (10.3)% 4.2 %1,861
 1,679
 1,626
 10.8 % 14.5 %
Volume. The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2018 compared to the same periods in 2017, primarily reflects the impact of residential customer growth.
Distribution Revenue. The increase in distribution revenues for the three and nine months ended September 30, 2018 compared to the same periods in 2017 was primarily due to higher electric distribution base rates charged to customers in Maryland that became effective in October 2017 and June 2018 and higher electric distribution base rates charged to customers in the District of Columbia that became

Table of Contents

effective August 2017 and August 2018, partially offset by the impact of reduced distribution rates to reflect the lower federal income tax rate. See Note 6—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs.This represents the change in operatingOperating 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 Taxes other than income in Pepco's Consolidated Statements of Operations and Comprehensive Income. Refer to theSee Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs. Revenue from regulatory required programs increased for the three and nine months ended September 30, 2018 compared to the same periods in 2017 due to increases in the Maryland and District of Columbia surcharge rates and sales due to higher volumes, as well as the DC PLUG surcharge which became effective in February 2018.
Transmission RevenuesRevenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, the highest daily peak load and other billing adjustments. The increase in transmission revenue net of purchased power expense for the three months ended September 30, 20172018 compared to the same period in 20162017 is a result of higher rates effective June 1, 2017 related to increases2018. The decrease in transmission plant investment and operating expenses. The increase in revenue net of purchased power expense for the nine months ended September 30, 2017 compared to the same period in 20162018 is a result of a decrease in network transmission service peak loads, partially offset by higher rates effective June 1, 2017 and June 1, 2016 related2018.
Other.Other revenue, which can vary period to increases in transmission plant investment and operating expenses, partially offset by lowerperiod, includes rental revenue, revenue related to the MAPP abandonment recovery period that ended in March 2016.late payment charges, assistance provided to other utilities through mutual assistance programs, and recoveries of other taxes.

236
Table of Contents


Other. The decrease in other operating revenue net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 is primarily due to lower pass-through revenue (which is substantially offset in Taxes other than income) primarily the result of lower sales that resulted in a decrease in utility taxes that are collected by Pepco on behalf of the jurisdiction.
Operating and Maintenance Expense
Three Months Ended  
 September 30,		 Increase (Decrease) Nine Months Ended 
 September 30,		 
Increase
(Decrease)
Three Months Ended
September 30,		 Increase (Decrease) Nine Months Ended
September 30,		 
Increase
(Decrease)
2017 2016 2017 2016 2018 2017 2018 2017 
Operating and maintenance expense - baseline$100
 $106
 $(6) $331
 $500
 $(169)$133
 $99
 $34
 $374
 $326
 $48
Operating and maintenance expense - regulatory required programs(a)
3
 3
 —
 5
 8
 (3)3
 4
 (1) 9
 10
 (1)
Total operating and maintenance expense$103
 $109
 $(6) $336
 $508
 $(172)$136
 $103
 $33
 $383
 $336
 $47
_________
(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.

Table of Contents

The changes in Operating and maintenance expense for the three and nine months ended September 30, 20172018 compared to the same periods in 2016,2017, consisted of the following:
 Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor, other benefits, contracting and materials$2
 $14
Storm-related costs(1) —
Remeasurement of AMI-related regulatory asset(a)
(4) (11)
Uncollectible accounts expense1
 (1)
Deferral of merger-related costs to regulatory asset(8) (1)
Deferral of rate case and customer billing system costs(6) (6)
BSC and PHISCO allocations(b)
1
 (22)
Merger commitments(c)
13
 (132)
Other(4) (10)
 (6) (169)
Regulatory required programs   
Purchased power administrative costs—
 (3)
Total decrease$(6) $(172)
 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
ARO update(a)
22
 22
Merger costs(b)
8
 14
Labor and contracting(c)
(2) 3
Other6
 9
 34
 48
    
Regulatory required programs(1) (1)
Total increase$33
 $47
_________
(a)RelatedReflects an increase primarily related to a remeasurementasbestos identified at the Buzzard Point property. See Note 13 - Asset Retirement Obligations of a regulatory assetthe Combined Notes to Consolidated Financial Statements for legacy meters recognized in 2016.additional information.
(b)Primarily relateddue to a deferral of accumulated merger severance and compensationintegration costs recognizedas regulatory assets in 2016.2017.
(c)Primarily related to merger-related commitments for customer rate creditsIncludes additional costs associated with mutual assistance programs. An equal and charitable contributionsoffsetting increase has been recognized in 2016.Operating revenues for the period presented.
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 20172018 compared to the same periodsperiod in 2016,2017, consisted of the following:

237
Table of Contents


Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$9
 $25
$3
 $8
Regulatory asset amortization(b)3
 4
10
 16
Regulatory required programs(b)(c)
(6) (8)4
 20
Total increase$6
 $21
$17
 $44
_________
(a)Depreciation expense increased due to higher depreciation rates in Maryland effective November 2016 and due to ongoing capital expenditures.
(b)Regulatory asset amortization increased primarily due to additional regulatory assets related to rate case activity.
(c)Regulatory required programs increased as a result of higher amortization of the DC PLUG regulatory asset. Depreciation and amortization expenses for regulatory required programs 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 and Operating and maintenance expense.revenues.
Taxes Other Than Income
Taxes other than income for the three andmonths ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Taxes other than income for the nine months ended September 30, 20172018 compared to the same periodsperiod in 2016, decreased2017, increased due to a decreasean increase in the utility taxes that are collected and passed through by Pepco (which is substantially offset in Operating revenues), partially offset by higher property taxes..

Table of Contents

Gain on salesSales of assetsAssets
The decrease in Gain on sales of assets forduring the nine months ended September 30, 20172018, compared to the same period in 2016 decreased2017, is primarily due to a second quarter 2016 gain recorded from the sale of land.land in June 2017.
Interest Expense, Net
Interest expense, net for the three months ended September 30, 2017 compared to the same period in 2016, remained relatively constant.
Interest expense, net for theand nine months ended September 30, 20172018 compared to the same periodperiods in 2016 decreased primarily2017 increased due to the recording of interest expense for an uncertain tax position in the first quarter of 2016 and an increase in capitalized AFUDC interest.higher outstanding debt.
Other, Net
Other, net for the three and nine months ended September 30, 20172018 compared to the same periods in 2016 decreased primarily due to the September 2016 reversal of contributions in aid of construction tax gross-up reserves due to the determination that there is no legal obligation to refund customers per contract terms.2017 remained relatively consistent.
Effective Income Tax Rate
Pepco's effective income tax rate was 30.4%(2.3)% and 30.7%30.4% for the three months ended September 30, 2018 and 2017, and 2016, respectively. The decrease in the effective income tax rate for the three months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA.
Pepco's effective income tax rate was 23.3%3.9% and 63.0%23.3% for the nine months ended September 30, 2018 and 2017, and 2016, respectively. In the first quarter of 2017, Pepco decreased its liability for unrecognized tax benefits by $21 million resulting in a benefit to Income taxes and a correspondingThe decrease in itsthe effective income tax rate. rate for the nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA, partially offset by a nonrecurring adjustment to income tax reserve balances in 2017.
See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

238
Table of Contents


Pepco Electric Operating Statistics and Revenue Detail
Three Months Ended  
 September 30,		     Nine Months Ended 
 September 30,		    
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		   Weather - Normal % Change Nine Months Ended
September 30,		   Weather - Normal % Change
2017 2016 % Change Weather - Normal % Change 2017 2016 % Change Weather - Normal % Change2018 2017 % Change 2018 2017 % Change 
Retail Deliveries(a)
                              
Residential2,281
 2,675
 (14.7)% (5.2)% 6,038
 6,652
 (9.2)% (2.7)%2,446
 2,281
 7.2 % 1.4 % 6,528
 6,038
 8.1 % 0.1 %
Small commercial & industrial347
 394
 (11.9)% (7.2)% 999
 1,124
 (11.1)% (8.4)%327
 347
 (5.8)% (8.1)% 982
 999
 (1.7)% (4.8)%
Large commercial & industrial4,146

4,314
 (3.9)% 0.8 % 11,306
 11,890
 (4.9)% (3.0)%4,298

4,146
 3.7 % 1.3 % 11,661
 11,306
 3.1 % 1.0 %
Public authorities & electric railroads180
 180
 — % 1.1 % 542
 544
 (0.4)% (0.2)%181
 180
 0.6 % — % 531
 542
 (2.0)% (2.6)%
Total retail deliveries6,954
 7,563
 (8.1)% (1.7)% 18,885
 20,210
 (6.6)% (3.1)%7,252
 6,954
 4.3 % 0.8 % 19,702
 18,885
 4.3 % 0.3 %
 As of September 30,
Number of Electric Customers2017 2016
Residential790,032
 775,911
Small commercial & industrial

53,543
 53,425
Large commercial & industrial21,733
 21,315
Public authorities & electric railroads143
 129
Total865,451
 850,780
 Three Months Ended  
 September 30,		   Nine Months Ended 
 September 30,		  
Electric Revenue2017 2016 % Change 2017 2016 % Change
Retail Sales(a)
           
Residential$283
 $315
 (10.2)% $744
 $791
 (5.9)%
Small commercial & industrial38
 43
 (11.6)% 113
 116
 (2.6)%
Large commercial & industrial221
 219
 0.9 % 608
 613
 (0.8)%
Public authorities & electric railroads8
 7
 14.3 % 24
 23
 4.3 %
Total retail550
 584
 (5.8)% 1,489
 1,543
 (3.5)%
Other revenue(b)
54
 51
 5.9 % 160
 152
 5.3 %
Total electric revenue(c)
$604
 $635
 (4.9)% $1,649
 $1,695
 (2.7)%
 As of September 30,
Number of Electric Customers2018 2017
Residential802,607
 790,032
Small commercial & industrial53,700
 53,543
Large commercial & industrial21,927
 21,733
Public authorities & electric railroads147
 143
Total878,381
 865,451
_________
(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 $1 million for the three months ended September 30, 2017 and 2016 and $4 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

239
Table of Contents


ResultsRevenues Net of Operations - DPLPurchased Power Expense
There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC, and ZEC procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity, REC, and ZEC procurement costs from retail customers without mark-up. Therefore, fluctuations in these costs have no impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Exelon 2017 Form 10-K 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 three and nine months ended September 30, 2018 and 2017, consisted of the following:
 Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2017 2016  2017 2016 
Operating revenues$327
 $331
 $(4) $971
 $974
 $(3)
Purchased power and fuel expense129
 150
 21
 399
 448
 49
Revenues net of purchased power and fuel expense(a)
198
 181
 17
 572
 526
 46
Other operating expenses

 

   

 

  
Operating and maintenance79
 55
 (24) 227
 338
 111
Depreciation and amortization45
 44
 (1) 124
 120
 (4)
Taxes other than income15
 14
 (1) 43
 42
 (1)
Total other operating expenses139
 113
 (26) 394
 500
 106
Gain on sales of asset—
 4
 (4) —
 4
 (4)
Operating income59
 72
 (13) 178
 30
 148
Other income and (deductions)

 

 

 

 

 

Interest expense, net(13) (12) (1) (38) (37) (1)
Other, net4
 3
 1
 10
 9
 1
Total other income and (deductions)(9) (9) —
 (28) (28) —
Income before income taxes50

63
 (13) 150

2
 148
Income taxes19
 19
 —
 43
 18
 (25)
Net income (loss)$31
 $44
 $(13) $107
 $(16) $123
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric67% 68% 68% 70%
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2018 and 2017 consisted of the following:
 September 30, 2018 September 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric1,367,700
 34% 1,360,800
 34%
The changes in ComEd’s Revenue net of purchased power expense for the three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Electric distribution revenue$(59) $(126)
Transmission revenue(16) (32)
Energy efficiency revenue(a)
14
 31
Regulatory required programs(a)
(1) (95)
Uncollectible accounts recovery, net2
 5
Other(3) 37
Total decrease$(63) $(180)
_________
(a)DPLBeginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

Table of Contents

Revenue Decoupling. The demand for electricity is affected by weather conditions. Under FEJA, ComEd revised its electric distribution rate formula effective January 1, 2017 to eliminate the favorable and unfavorable impacts on Operating revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage 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 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 three and nine months ended September 30, 2018 and 2017, consisted of the following:
Heating and Cooling Degree-Days      % Change
Three Months Ended September 30,2018 2017 Normal2018 vs. 2017 2018 vs. Normal
Heating Degree-Days56
 42
 97
 33.3% (42.3)%
Cooling Degree-Days895
 699
 641
 28.0% 39.6 %
          
Nine Months Ended September 30,         
Heating Degree-Days3,993
 3,269
 3,972
 22.1% 0.5 %
Cooling Degree-Days1,259
 962
 882
 30.9% 42.7 %
Electric Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. 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. Electric distribution revenue decreased during the three and nine months ended September 30, 2018, primarily due to the impact of the lower federal income tax rate, partially offset by increased revenues due to higher rate base and increased depreciation expense as compared to the same period in 2017. See Depreciation and amortization expense discussions below and Note 6 — Regulatory Matters and Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. For the three months ended September 30, 2018, ComEd recorded decreased transmission revenue primarily due to the impact of the lower federal income tax rate, partially offset by increased revenues due to higher rate base and increased depreciation expense as compared to the same period in 2017. For the nine months ended September 30, 2018, ComEd recorded decreased transmission revenue primarily due to the decreased peak load and the impact of the lower federal income tax rate, partially offset by increased revenues due to higher rate base and increased depreciation expense as compared to the same period in 2017. See Operating and maintenance expense below and Note 6 — Regulatory Matters and Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue. Beginning June 1, 2017, FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual

Table of Contents

costs that the ICC determines are prudently and reasonably incurred in a given year.  Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE 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. See Depreciation and amortization expense discussions below and Note 6 — 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 rate riders to recover costs incurred for regulatory programs such as ComEd’s purchased power administrative costs and energy efficiency and demand response through June 1, 2017 pursuant to FEJA. The riders are designed to provide full and current cost recovery. 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.
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. The increase in Other revenue for the nine months ended September 30, 2018 compared to the same period in 2017 primarily reflects mutual assistance revenues associated with hurricane and winter storm restoration efforts. An equal and offsetting amount has been included in Operating and maintenance expense and Taxes other than income.
Operating and Maintenance Expense
 Three Months Ended
September 30,		 
Increase
(Decrease)
 Nine Months Ended
September 30,		 Increase (Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense — baseline$336
 $344
 $(8) $973
 $1,000
 $(27)
Operating and maintenance expense — regulatory required programs(a)
1
 2
 $(1) 1
 96
 (95)
Total Operating and maintenance expense$337

$346

$(9)
$974

$1,096

$(122)
_________
(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.

Table of Contents

The decrease in Operating and maintenance expense for the three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor, other benefits, contracting and materials(a)
$(1) $(3)
Pension and non-pension postretirement benefits expense(a)
(1) (1)
Storm-related costs(5) (21)
Uncollectible accounts expense — provision(b)
7
 11
Uncollectible accounts expense — recovery, net(b)
(5) (6)
BSC costs(a)
(9) (8)
Other(a)
6
 1
 (8) (27)
Regulatory required programs   
Energy efficiency and demand response programs(c)
(1) (95)
Decrease in operating and maintenance expense$(9) $(122)
_________
(a)Includes additional costs associated with mutual assistance programs. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
(b)ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. During the three and nine months ended September 30, 2018, ComEd recorded a net increase in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
(c)Beginning June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.
Depreciation and Amortization Expense
The increase in Depreciation and amortization expense during the three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase Increase
Depreciation expense(a)
$9
 $30
Regulatory asset amortization(b)
16
 35
Total increase$25
 $65
_________
(a)Primarily reflects ongoing capital expenditures for the three and nine months ended September 30, 2018.
(b)Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset.
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.

Table of Contents

Gain on Sales of Assets
The increase in Gain on sales of assets during the nine months ended September 30, 2018 compared to the same period in 2017, is primarily due to the sale of land in March 2018.
Interest Expense, Net
The changes in Interest expense, net, for the three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Interest expense related to uncertain tax positions(a)
$—
 $(13)
Interest expense on debt (including financing trusts)(2) 2
Other(2) (3)
Total decrease$(4) $(14)
__________
(a)Primarily reflects additional interest recorded in the second quarter of 2017 related to Exelon's like-kind exchange tax position.
Other, Net
Other, net, remained relatively consistent for the three and nine months ended September 30, 2018 compared to the same period in 2017.
Effective Income Tax Rate
ComEd's effective income tax rate was 21.2% and 40.9% for the three months ended September 30, 2018 and 2017, respectively. ComEd's effective income tax rate was 21.1% and 42.3% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

ComEd Electric Operating Statistics Detail
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		 % Change 
Weather-
Normal
% Change
 Nine Months Ended
September 30,		 % Change 
Weather-
Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential8,845
 8,004
 10.5 % (1.5)% 22,019
 20,164
 9.2% 0.1%
Small commercial & industrial8,626
 8,488
 1.6 % (1.0)% 24,204
 23,634
 2.4% —%
Large commercial & industrial7,450
 7,232
 3.0 % 1.1 % 21,398
 20,712
 3.3% 1.6%
Public authorities & electric railroads301
 302
 (0.3)% (0.5)% 947
 928
 2.0% 1.2%
Total retail deliveries25,222

24,026
 5.0 % (0.5)% 68,568

65,438
 4.8% 0.6%
 As of September 30,
Number of Electric Customers2018 2017
Residential3,635,678
 3,610,091
Small commercial & industrial380,529
 376,309
Large commercial & industrial1,994
 1,954
Public authorities & electric railroads4,767
 4,763
Total4,022,968

3,993,117
_________
(a)Reflects delivery 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.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

Table of Contents

Results of Operations — PECO
 Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$757
 $715
 $42
 $2,275
 $2,141
 $134
Purchased power and fuel expense263
 235
 (28) 818
 719
 (99)
Revenues net of purchased power and fuel expense(a)
494
 480
 14
 1,457
 1,422
 35
Other operating expenses           
Operating and maintenance219
 197
 (22) 686
 595
 (91)
Depreciation and amortization75
 72
 (3) 224
 213
 (11)
Taxes other than income46
 42
 (4) 125
 116
 (9)
Total other operating expenses340
 311
 (29) 1,035
 924
 (111)
Gain on sales of assets—
 —
 —
 1
 —
 1
Operating income154
 169
 (15) 423
 498
 (75)
Other income and (deductions)           
Interest expense, net(32) (31) (1) (96) (93) (3)
Other, net2
 2
 —
 4
 6
 (2)
Total other income and (deductions)(30) (29) (1) (92) (87) (5)
Income before income taxes124
 140
 (16) 331
 411
 (80)
Income taxes(2) 28
 30
 (5) 84
 89
Net income$126
 $112
 $14
 $336
 $327
 $9
_________
(a)PECO evaluates its operating performance using the measuremeasures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for natural gas sales. DPLPECO 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 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 presentations 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
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017.PECO's Net income increased from the same period in 2017, primarily due to higher Operating revenues net of purchase power and fuel expense attributable to favorable weather and volume. The TCJA did not significantly impact PECO's Net income for the three and nine months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the requirement to pass back the tax savings through customer rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.PECO's Net income increased from the same period in 2017, primarily due to higher Operating revenues net of purchase power and fuel expense attributable to favorable weather and volume, partially offset by higher Operating and maintenance expense attributable to increased storm restoration costs as a result of winter storms in March 2018. The TCJA did not significantly impact PECO's Net income for the three and nine months ended September 30, 2018 as the favorable income tax impacts were

Table of Contents

predominantly offset by lower revenues resulting from the requirement to pass back the tax savings through customer rates.
Revenues Net of Purchased Power and Fuel Expense
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 revenue 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 revenues net of purchased 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 three and nine months ended September 30, 2018 and 2017, consisted of the following:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric68% 70% 69% 71%
Natural Gas31% 29% 26% 26%
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2018 and 2017 consisted of the following:
 September 30, 2018 September 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric536,000
 33% 570,500
 35%
Natural Gas88,900
 17% 82,600
 16%

Table of Contents

The changes in PECO’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
 Electric Natural Gas Total Electric Natural Gas Total
Weather$20
 $1
 $21
 $39
 $19
 $58
Volume17
 (1) 16
 26
 2
 28
Pricing(36) 3
 (33) (66) (5) (71)
Regulatory required programs7
 —
 7
 5
 —
 5
Other3
 —
 3
 18
 (3) 15
Total increase$11
 $3
 $14
 $22
 $13
 $35
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2018 compared to the same period in 2017, Operating revenue net of purchased power and fuel increased due to favorable weather conditions.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and nine months ended September 30, 2018 compared to the same period in 2017 and normal weather consisted of the following:
Heating and Cooling Degree-Days  Normal % Change
Three Months Ended September 30,2018 2017From 2017 2018 vs. Normal
Heating Degree-Days13
 14
 27
 (7.1)% (51.9)%
Cooling Degree-Days1,124
 989
 999
 13.7 % 12.5 %
          
Nine Months Ended September 30,         
Heating Degree-Days2,892
 2,437
 2,912
 18.7 % (0.7)%
Cooling Degree-Days1,506
 1,404
 1,383
 7.3 % 8.9 %
Volume. Operating revenue net of purchased power related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2018 compared to the same period in 2017, increased due to the impact of moderate economic and customer growth partially offset by the impact of energy efficiency initiatives on customer usages primarily in the residential class. Additionally, the increase represents a shift in the volume profile across classes from the commercial and industrial classes to the residential class.
Pricing.Operating revenues net of purchased power as a result of pricing for the three and nine months ended September 30, 2018 and operating revenues net of fuel as the result of pricing for the nine months ended September 30, 2018 compared to the same periods in 2017 decreased primarily due to the pass back through customers rates the tax savings associated with the lower federal income

Table of Contents

tax rate. See Note 6 — 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 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. See 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
 Three Months Ended
September 30,		 
Increase
(Decrease)
 Nine Months Ended
September 30,		 Increase
(Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense — baseline$198
 $183
 $15
 $632
 $552
 $80
Operating and maintenance expense — regulatory required programs(a)
21
 14
 7
 54
 43
 11
Total Operating and maintenance expense$219
 $197
 $22
 $686
 $595
 $91
_________
(a)Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
The changes in Operating and maintenance expense for the three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor, other benefits, contracting and materials$(1) $10
Storm-related costs(a)
2
 61
Pension and non-pension postretirement benefits expense(2) (5)
Uncollectible accounts expense6
 8
Other10
 6
 15
 80
Regulatory Required Programs   
Energy efficiency7
 11
Total increase$22
 $91
__________
(a)Reflects increased costs incurred from the Q1 2018 winter storms.

Table of Contents

Depreciation and Amortization Expense
Depreciation and amortization expense increased primarily due to ongoing capital spend for the three and nine months ended September 30, 2018 compared to the same period in 2017.
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income increased for the three and nine months ended September 30, 2018 compared to the same period in 2017 due to an increase in gross receipts tax driven by an increase in electric revenue.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2018 remained relatively consistent compared to the same period in 2017.
Other, Net
Other, net for the three and nine months ended September 30, 2018 remained consistent compared to the same period in 2017.
Effective Income Tax Rate
PECO's effective income tax rate was (1.6)% and 20.0% for the three months ended September 30, 2018 and 2017, respectively. PECO's effective income tax rate was (1.5)% and 20.4% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

PECO Electric Operating Statistics
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		 % Change 
Weather -
Normal
% Change
 Nine Months Ended
September 30,		 % Change Weather -
Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential4,166
 3,752
 11.0 % 4.7 % 10,741
 9,939
 8.1 % 2.8 %
Small commercial & industrial2,315
 2,158
 7.3 % 2.0 % 6,273
 6,048
 3.7 % 0.4 %
Large commercial & industrial4,378
 4,137
 5.8 % 4.9 % 11,892
 11,593
 2.6 % 2.5 %
Public authorities & electric railroads189
 198
 (4.5)% (4.8)% 568
 618
 (8.1)% (7.7)%
Total retail deliveries11,048

10,245
 7.8 % 4.0 % 29,474

28,198
 4.5 % 1.9 %
 As of September 30,
Number of Electric Customers2018 2017
Residential1,476,914
 1,463,906
Small commercial & industrial152,253
 150,964
Large commercial & industrial3,124
 3,112
Public authorities & electric railroads9,561
 9,665
Total1,641,852
 1,627,647
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

Table of Contents

PECO Natural Gas Operating Statistics
Deliveries to Customers (in mmcf)Three Months Ended
September 30,		 % Change 
Weather -
 Normal
% Change
 Nine Months Ended
September 30,		 % Change 
Weather -
 Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential2,099
 2,177
 (3.6)% 0.9% 28,562
 24,866
 14.9% 0.2 %
Small commercial & industrial1,776
 1,814
 (2.1)% 0.2% 15,792
 13,944
 13.3% 1.0 %
Large commercial & industrial6
 2
 200.0 % 12.8% 58
 15
 286.7% 278.3 %
Transportation5,693
 5,674
 0.3 % 3.2% 19,242
 19,122
 0.6% (3.8)%
Total natural gas deliveries9,574
 9,667
 (1.0)% 1.6% 63,654
 57,947
 9.8% (0.8)%
 As of September 30,
Number of Natural Gas Customers2018 2017
Residential479,732
 474,766
Small commercial & industrial43,638
 43,352
Large commercial & industrial1
 6
Transportation761
 771
Total524,132

518,895
_________
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

Table of Contents

Results of Operations — BGE
 Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$731
 $738
 $(7) $2,369
 $2,363
 $6
Purchased power and fuel expense272
 269
 (3) 881
 853
 (28)
Revenues net of purchased power and fuel expense(a)
459
 469
 (10) 1,488
 1,510
 (22)
Other operating expenses           
Operating and maintenance182
 175
 (7) 578
 532
 (46)
Depreciation and amortization110
 109
 (1) 358
 348
 (10)
Taxes other than income64
 61
 (3) 188
 180
 (8)
Total other operating expenses356
 345
 (11) 1,124
 1,060
 (64)
Gain on sales of assets—
 —
 —
 1
 —
 1
Operating income103
 124
 (21) 365
 450
 (85)
Other income and (deductions)           
Interest expense, net(27) (26) (1) (78) (80) 2
Other, net5
 4
 1
 14
 12
 2
Total other income and (deductions)(22) (22) —
 (64) (68) 4
Income before income taxes81
 102
 (21) 301
 382
 (81)
Income taxes18
 40
 22
 59
 151
 92
Net income$63
 $62
 $1
 $242
 $231
 $11
_________
(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
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017. BGE’s Net income for the three months ended September 30, 2018 was relatively consistent with the same period in 2017. The TCJA did not significantly impact BGE's net income for the three months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017. BGE’s Net income for the nine months ended September 30, 2018 was higher than the same period in 2017, due primarily to higher transmission revenues, partially offset by an increase in Operating and maintenance expense attributable to increased storm restoration costs as a result of storms in March 2018 and September 2018. The TCJA did not significantly impact BGE's net income for the nine months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.

Table of Contents

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. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on 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 the number of customers electing to use a competitive supplier for electricity and/or natural gas. All BGE customers have the choice to purchase electricity and natural gas from competitive suppliers. The customers' choice of suppliers does not impact the volume of deliveries but does affect revenue collected from customers related to supplied electricity and natural gas.
Retail deliveries purchased from competitive electricity and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30, 2018 and 2017 consisted of the following:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric59% 60% 59% 60%
Natural Gas76% 74% 56% 57%
The number of retail customers purchasing electricity and natural gas from competitive suppliers at September 30, 2018 and 2017 consisted of the following:
 September 30, 2018 September 30, 2017
 Number of Customers % of total retail customers Number of customers % of total retail customers
Electric335,200
 26% 339,300
 27%
Natural Gas147,400
 22% 148,600
 22%

Table of Contents

The changes in BGE’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2018, compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
 Electric Gas Total Electric Gas Total
Distribution revenue$(17) $(2) $(19) $(48) $(19) $(67)
Regulatory required programs1
 (1) —
 3
 2
 5
Transmission revenue6
 —
 6
 23
 —
 23
Other, net—
 3
 3
 6
 11
 17
Total decrease$(10) $—
 $(10) $(16) $(6) $(22)
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 fluctuations in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved distribution charges 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 volatility in 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 three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
Heating and Cooling Degree-Days      % Change
Three Months Ended September 30,2018 2017 Normal 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days31
 64
 76
 (51.6)% (59.2)%
Cooling Degree-Days733
 595
 601
 23.2 % 22.0 %
          
Nine Months Ended September 30,         
Heating Degree-Days2,969
 2,524
 2,974
 17.6 % (0.2)%
Cooling Degree-Days1,032
 877
 857
 17.7 % 20.4 %
Distribution Revenue. The decrease in distribution revenues for the three and nine months ended September 30, 2018, compared to the same period in 2017, was primarily due to the impact of reduced distribution rates to reflect the lower federal income tax rate. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Table of Contents

Regulatory Required Programs. Revenue from regulatory required programs are billings for the costs of various legislative and/or regulatory programs that are recoverable from customers on a full and current basis. These programs are designed to provide full cost recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income 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 rate adjustments to reflect fluctuations in the underlying costs, capital investments being recovered and other billing determinants. The increase in transmission revenue for the three and nine months ended September 30, 2018, compared to the same period in 2017, was primarily due to increases in capital investment and operating and maintenance expense recoveries. See Operating and Maintenance Expense below and Note 6 — 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, primarily includes assistance provided to other utilities through BGE's mutual assistance program, service application fees, and other miscellaneous revenue such as off-system sales and administrative charges.
Operating and Maintenance Expense
 Three Months Ended
September 30,		 
Increase
(Decrease)
 Nine Months Ended
September 30,		 Increase
(Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense — baseline$180
 $172
 $8
 $572
 $520
 $52
Operating and maintenance expense — regulatory required programs(a)
2
 3
 (1) 6
 12
 (6)
Total Operating and maintenance expense$182
 $175
 $7
 $578
 $532
 $46
_________
(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.

Table of Contents

The changes in Operating and maintenance expense for the three and nine months ended September 30, 2018, compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Storm-related costs(a)
$5
 $36
Labor, other benefits, contracting and materials1
 2
Uncollectible accounts expense1
 3
BSC costs(1) 4
Other2
 7
 8
 52
Regulatory Required Programs   
Other(1) (6)
Total increase$7
 $46
__________
(a)Reflects increased storm restoration costs incurred from storms in Q1 2018 and Q3 2018.
Depreciation and Amortization
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2018, compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$8
 $17
Regulatory asset amortization(b)
(8) (18)
Regulatory required programs(c)
1
 11
Total increase$1
 $10
_________
(a)Depreciation expense increased due to ongoing capital expenditures.
(b)Regulatory asset amortization decreased for the three and nine months ended September 30, 2018 compared to the same period in 2017 primarily due to certain regulatory assets that became fully amortized as of December 31, 2017. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(c)Depreciation and amortization expenses for regulatory required programs 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.
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 2018, compared to the same period in 2017, increased primarily due to an increase in property taxes.
Gain on Sales of Assets
Gain on sales of assets, for the three months ended September 30, 2018 compared to the same period in 2017, remained relatively consistent. The increase in Gain on sales of assets during the nine

Table of Contents

months ended September 30, 2018, compared to the same period in 2017, is due to the sale of land in June 2018.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2018, compared to the same period in 2017, remained relatively consistent.
Other, Net
Other, net for the three and nine months ended September 30, 2018, compared to the same period in 2017, remained relatively consistent.
Effective Income Tax Rate
BGE’s effective income tax rate was 22.2% and 39.2% for the three months ended September 30, 2018 and 2017, respectively. BGE's effective income tax rate was 19.6% and 39.5% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and nine months ended September 30, 2018, compared to the same periods in 2017, is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — 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 Detail
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		 % Change Weather -
Normal
% Change		 Nine Months Ended
September 30,		 % Change Weather -
Normal
% Change
2018
2017  2018 2017 
Retail Deliveries(a)
               
Residential3,663
 3,370
 8.7% 1.8 % 9,960
 9,126
 9.1 % 1.8 %
Small commercial & industrial825
 785
 5.1% (1.1)% 2,309
 2,210
 4.5 % (0.2)%
Large commercial & industrial3,909
 3,781
 3.4% 0.6 % 10,661
 10,422
 2.3 % (0.1)%
Public authorities & electric railroads64
 64
 —% (5.9)% 200
 204
 (2.0)% (4.1)%
Total electric deliveries8,461
 8,000
 5.8% 0.9 % 23,130
 21,962
 5.3 % 0.7 %
 As of September 30,
Number of Electric Customers2018 2017
Residential1,165,012
 1,156,659
Small commercial & industrial114,082
 113,224
Large commercial & industrial12,218
 12,144
Public authorities & electric railroads263
 274
Total1,291,575
 1,282,301
_________
(a)Reflects delivery 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.

Table of Contents

BGE Natural Gas Operating Statistics and Detail
Deliveries to Customers (in mmcf)Three Months Ended
September 30,		 % Change Weather -
Normal
% Change		 Nine Months Ended
September 30,		 % Change Weather -
Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential2,244
 2,395
 (6.3)% (4.5)% 29,290
 24,125
 21.4% 3.2%
Small commercial & industrial813
 814
 (0.1)% 0.4 % 7,020
 5,667
 23.9% 7.2%
Large commercial & industrial8,227
 8,012
 2.7 % 2.2 % 34,044
 30,828
 10.4% 5.9%
Other(b)
3,144
 68
 4,523.5 % n/a
 11,183
 2,463
 354.0% n/a
Total natural gas deliveries14,428
 11,289
 27.8 % 0.6 % 81,537
 63,083
 29.3% 4.9%
 As of September 30,
Number of Gas Customers2018
2017
Residential631,589
 626,039
Small commercial & industrial38,175
 38,141
Large commercial & industrial5,920
 5,832
Total675,684

670,012
_________
(a)Reflects delivery volumes 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.
(b)Other natural gas revenue includes off-system sales of 3,144 mmcfs and 68 mmcfs for the three months ended September 30, 2018 and 2017, respectively. Other natural gas revenue includes off-system sales of 11,183 mmcfs and 2,463 mmcfs for the nine months ended September 30, 2018 and 2017. respectively.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

Table of Contents

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. 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.
 Three Months Ended
September 30,		 Favorable (Unfavorable) Variance Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$1,361
 $1,310
 $51
 $3,688
 $3,557
 $131
Purchased power and fuel expense509
 473
 (36) 1,410
 1,318
 (92)
Revenues net of purchased power and fuel expense(a)
852
 837
 15
 2,278
 2,239
 39
Other operating expenses           
Operating and maintenance292
 251
 (41) 857
 774
 (83)
Depreciation and amortization192
 179
 (13) 555
 511
 (44)
Taxes other than income123
 122
 (1) 343
 344
 1
Total other operating expenses607
 552
 (55) 1,755
 1,629
 (126)
Gain on sales of assets—
 —
 —
 —
 1
 (1)
Operating income245
 285
 (40) 523
 611
 (88)
Other income and (deductions)           
Interest expense, net(65) (62) (3) (193) (183) (10)
Other, net11
 13
 (2) 33
 40
 (7)
Total other income and (deductions)(54) (49) (5) (160) (143) (17)
Income before income taxes191
 236
 (45) 363
 468
 (105)
Income taxes4
 83
 79
 28
 109
 81
Equity in earnings of unconsolidated affiliate—
 —
 —
 1
 —
 1
Net income$187
 $153
 $34
 $336
 $359
 $(23)
_________
(a)PHI evaluates its operating performance using the measure of revenue net of purchased power and fuel expense for electric and natural gas sales. PHI believes revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. DPLPHI 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.
Net Income (Loss)
Three Months Ended September 30, 20172018 Compared to Three Months Ended September 30, 2016. DPL's2017.PHI's Net income for the three months ended September 30, 2018 was $187 million compared to $153 million for the three months ended September 30, 2017.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $15 million for the three months ended September 30, 2018 compared to the same period in 2017 primarily due to higher utility revenues due to distribution rate increases at Pepco, DPL, and ACE, as well as favorable weather and volume, partially offset by lower revenues resulting from the pass back of TCJA tax savings through customer rates.

Table of Contents

Operating and maintenance expense increased by $41 million for the three months ended September 30, 2018 compared to the same period in 2017. The increase is primarily due to the following factors:
Increase of $22 million at Pepco due to a charge associated with a remeasurement of the Buzzard Point ARO; and
Increase of $14 million primarily due to deferral of accumulated merger integration costs as regulatory assets in 2017.
Depreciation and amortization expense for the three months ended September 30, 2018 compared to the same period in 2017 increased by $13 million primarily due to ongoing capital expenditures as well as increased amortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues).
Taxes other than income for the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Gain on sales of assets during the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Interest expense, net for the three months ended September 30, 2018 compared to the same period in 2017 increased by $3 million due to higher outstanding debt.
Other, net for the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Equity in earnings for the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
PHI's effective income tax rate was 2.1% and 35.2% for the three months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.PHI's Net income for the nine months ended September 30, 2018 was $336 million compared to $359 million for the nine months ended September 30, 2017.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $39 million for the nine months ended September 30, 2018 compared to the same period in 2017 primarily due to higher utility revenues due to distribution rate increases at Pepco, DPL, and ACE, as well as favorable weather and volume, partially offset by lower revenues resulting from the pass back of TCJA tax savings through customer rates.

Table of Contents

Operating and maintenance expense increased by $83 million for the nine months ended September 30, 2018 compared to the same period in 2017. The increase is primarily due to the following factors:
Increase of $28 million primarily due to deferral of accumulated merger integration costs as regulatory assets in 2017;
Net increase of $23 million in labor and contracting expense due to an increase of $32 million at Pepco, DPL and ACE partially offset by a decrease of $9 million at PHISCO as a result of the completion of integration transition activities; and
Increase of $22 million at Pepco due to a charge associated with a remeasurement of the Buzzard Point ARO.
Depreciation and amortization expense for the nine months ended September 30, 2018 compared to the same period in 2017 increased by $44 million primarily due to ongoing capital expenditures as well as increased amortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues).
Taxes other than income for the nine months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Gain on sales of assets during the nine months ended September 30, 2018 compared to the same period in 2017 decreased $1 million due to the sale of land in June 2017.
Interest expense, net for the nine months ended September 30, 2018 compared to the same period in 2017 increased $10 million due to higher outstanding debt.
Other, net for the nine months ended September 30, 2018 compared to the same period in 2017 decreased $7 million primarily due to lower income from AFUDC equity.
Equity in earnings for the nine months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
PHI's effective income tax rate was 7.7% and 23.3% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA, partially offset by a nonrecurring adjustment to income tax reserve balances in 2017. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

Results of Operations - Pepco
 Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2018 2017  2018 2017 
Operating revenues$628
 $604
 $24
 $1,708
 $1,649
 $59
Purchased power expense177
 168
 (9) 497
 478
 (19)
Revenues net of purchased power expense(a)
451
 436
 15
 1,211
 1,171
 40
Other operating expenses           
Operating and maintenance136
 103
 (33) 383
 336
 (47)
Depreciation and amortization99
 82
 (17) 286
 242
 (44)
Taxes other than income104
 102
 (2) 288
 282
 (6)
Total other operating expenses339
 287
 (52) 957
 860
 (97)
Gain on sales of assets—
 —
 —
 —
 1
 (1)
Operating income112
 149
 (37) 254
 312
 (58)
Other income and (deductions)    
     
Interest expense, net(32) (31) (1) (96) (89) (7)
Other, net7
 7
 —
 23
 22
 1
Total other income and (deductions)(25) (24) (1) (73) (67) (6)
Income before income taxes87
 125
 (38) 181
 245
 (64)
Income taxes(2) 38
 40
 7
 57
 50
Net income$89
 $87
 $2
 $174
 $188
 $(14)
_________
(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
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017.Pepco's Net income for the three months ended September 30, 2018, was relatively consistent with the same period in 2017. The TCJA did not significantly impact Pepco's Net income for the three months ended September 30, 2018 as the favorable tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.Pepco's Net income for the nine months ended September 30, 2018, was lower than the same period in 2016 as a result of the merger commitment reallocation from DPL2017 primarily due to Exelon that decreasedhigher Operating and maintenance expense attributable to an increase in 2016,the asset retirement obligations related to the Buzzard Point property, deferral of accumulated merger integration costs as regulatory assets in 2017 and higher regulatory asset amortization due to additional regulatory assets related to rate case activity, partially offset by an increase in Revenue net of purchased power and fuel expense primarily resulting from higher electric distribution base rates charged to customers in Maryland that became effective in October 2017 and natural gas revenues as a resultJune 2018 and higher electric distribution base rates charged to customers in the District of the distribution rate increases approved by the DPSCColumbia that became effective July 2016August 2017 and December 2016 and by the MDPSC effective February 2017.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. DPL'sAugust 2018. The TCJA did not significantly impact Pepco's Net income (loss) for the nine

Table of Contents

months ended September 30, 2017, was higher than2018 as the same period in 2016 as a result of an increase in Revenue net of purchased power and fuel expense primarilyfavorable tax impacts were predominantly offset by lower revenues resulting from higher electric distribution and natural gas revenues as a resultthe pass back of the distribution rate increases approved by the DPSC effective July 2016 and December 2016 and by the MDPSC effective February 2017, lower Operating and maintenance expense due to merger-related costs recognized in March 2016, lower uncollectible accounts expense, and the deferral of merger-related costs to a regulatory asset in 2017, and a decrease in income tax reserves in the first quarter of 2017 for uncertain tax positions related to the deductibility of certain merger commitments.savings through customer rates.
Revenues Net of Purchased Power and Fuel Expense
Operating revenues include revenue from the distribution and supply of electricity to DPL’sPepco’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that DPLPepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

240
Table of Contents


Electric and natural 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 natural 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 three and nine months ended September 30, 2017 and 2016, consisted of the following:
 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
Electric51% 49% 52% 51%
Natural Gas53% 51% 35% 32%
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:
 September 30, 2017 September 30, 2016
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric78,426
 15.0% 79,501
 15.4%
Natural Gas155
 0.1% 157
 0.1%
Retail deliveries purchased from competitive electric generation suppliers represented 53% and 54% of DPL’s retail kWh sales to Delaware customers and 48% and 48% of DPL's retail kWh sales to Maryland customers for the three and nine months ended September 30, 2017, respectively and 51% and 53% of DPL's retail kWh sales to Delaware customers and 47% and 47% of DPL's retail kWh sales to Maryland customers for the three and nine months ended September 30, 2016, respectively.
Operating revenues include transmission enhancement credits that DPL 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.
Natural gas operating revenue includes sources that are subject to price regulation (Regulated Gas Revenue)Electric revenues 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.
Purchasedpurchased power expense consistsare 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 three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the cost of electricity purchased by DPL to fulfill its default electricity supply obligationfollowing:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric64% 65% 64% 66%
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2018 and as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased fuel expense consists2017 consisted of the costfollowing:
 September 30, 2018 September 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric175,838
 20% 179,106
 21%
Retail deliveries purchased from competitive electric generation suppliers represented 72% and 72% of gas purchased by DPLPepco’s retail kWh sales to fulfill its obligation to regulated gasthe District of Columbia customers and as such, is recoverable from58% and 58% of Pepco’s retail kWh sales to Maryland customers in accordance withfor the termsthree and nine months ended September 30, 2018, respectively and 72% and 73% of public service commission orders. It also includesPepco’s retail kWh sales to the costDistrict of gas purchasedColumbia customers and 60% and 60% of Pepco’s retail kWh sales to Maryland customers for off-system sales.the three and nine months ended September 30, 2017, respectively.

241
Table of Contents


The changes in DPL’sPepco’s operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 20172018 compared to the same periods in 20162017 consisted of the following:
 Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017
 Increase (Decrease)
 Increase (Decrease)
 Electric Gas Total Electric Gas Total
Weather$(6) $1
 $(5) $(9) $(13) $(22)
Volume2
 (1) 1
 3
 10
 13
Pricing - distribution revenues17
 —
 17
 49
 2
 51
Regulatory required programs(3) —
 (3) (2) —
 (2)
Transmission revenues5
 —
 5
 4
 —
 4
Other3
 (1) 2
 5
 (3) 2
Total increase (decrease)$18
 $(1) $17
 $50
 $(4) $46
 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
 Increase (Decrease) Increase (Decrease)
Volume$3
 $9
Distribution revenue6
 9
Regulatory required programs7
 27
Transmission revenue2
 (5)
Other(3) —
Total increase$15
 $40
Revenue Decoupling. DPL’sPepco’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 DPLPepco 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. 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 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.

242
Table of Contents


Weather. The demand for electricity and natural 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 natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2017 compared to the same periods in 2016, operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable weather conditions in DPL's service territory.
Heating and cooling degree daysdegree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree daysdegree-days for a 20-year period in DPL's electric service territory and a 30-year period in DPL's natural gasPepco's service territory. The changes in heating and cooling degree daysdegree-days in DPL’sPepco’s service territory for the three and nine months ended September 30, 20172018 compared to the same periods in 20162017 and normal weather consisted of the following:
Electric Service Territory    % Change
Three Months Ended September 30,2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days24
 14
 33
 71.4 % (27.3)%
Cooling Degree-Days867
 1,103
 856
 (21.4)% 1.3 %
          
Nine Months Ended September 30,         
Heating Degree-Days2,384
 2,812
 2,933
 (15.2)% (18.7)%
Cooling Degree-Days1,228
 1,410
 1,184
 (12.9)% 3.7 %
Natural Gas Service Territory    % Change
Heating and Cooling Degree-Days    % Change
Three Months Ended September 30,2017 2016 Normal 2017 vs. 2016 2017 vs. Normal2018 2017 Normal 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days28
 20
 42
 40.0 % (33.3)%2
 8
 13
 (75.0)% (84.6)%
Cooling Degree-Days1,283
 1,130
 1,137
 13.5 % 12.8 %
               

 

Nine Months Ended September 30,               

 

Heating Degree-Days2,431
 2,913
 3,062
 (16.5)% (20.6)%2,458
 1,963
 2,448
 25.2 % 0.4 %
Cooling Degree-Days1,861
 1,679
 1,626
 10.8 % 14.5 %
Volume.Volume. The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 20172018 compared to the same periods in 2016,2017, primarily reflects the impact of increased natural gas average customer usage andresidential customer growth.
Pricing—Distribution Revenues.Revenue. The increase in electric operatingdistribution revenues net of purchased power expense as a result of pricing for the three and nine months ended September 30, 20172018 compared to the same periods in 20162017 was primarily due to the impact of higher electric distribution and natural gasbase rates charged to Delaware customers in Maryland that became effective in JulyOctober 2017 and December 2016June 2018 and higher electric distribution base rates charged to customers in the District of Columbia that became

Table of Contents

effective August 2017 and August 2018, partially offset by the impact of higher electricreduced distribution rates charged to Maryland customers that became effective in February 2017.reflect the lower federal income tax rate. See Note 5—6—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs.This represents the change in operatingOperating 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 Taxes other than income in DPL'sPepco's Consolidated Statements of Operations and Comprehensive Income. Refer to theSee Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs. Revenue from regulatory required programs increased for the three and nine months ended September 30, 2018 compared to the same periods in 2017 due to increases in the Maryland and District of Columbia surcharge rates and sales due to higher volumes, as well as the DC PLUG surcharge which became effective in February 2018.
Transmission Revenues.Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, the highest daily peak load and other billing adjustments. The increase in transmission revenue net of purchased power expense for the three months ended September 30, 20172018 compared to the same period in 20162017 is a result of higher rates effective June 1, 2017 related to increases2018. The decrease in transmission plant investment and operating expenses. The increase in revenue net of purchased power expense for the nine months

243
Table of Contents


ended September 30, 2017 compared to the same period in 20162018 is a result of a decrease in network transmission service peak loads, partially offset by higher rates effective June 1, 2017 and June 1, 2016 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 2016.2018.
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, and recoveries of other taxes.
Operating and Maintenance Expense
Three Months Ended  
 September 30,		 Increase (Decrease) Nine Months Ended 
 September 30,		 Increase (Decrease)Three Months Ended
September 30,		 Increase (Decrease) Nine Months Ended
September 30,		 
Increase
(Decrease)
2017 2016 2017 2016 2018 2017 2018 2017 
Operating and maintenance expense - baseline$76
 $50
 $26
 $221
 $328
 $(107)$133
 $99
 $34
 $374
 $326
 $48
Operating and maintenance expense - regulatory required programs(a)
3
 5
 (2) 6
 10
 (4)3
 4
 (1) 9
 10
 (1)
Total operating and maintenance expense$79
 $55
 $24
 $227
 $338
 $(111)$136
 $103
 $33
 $383
 $336
 $47
_________
(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.

Table of Contents

The changes in Operating and maintenance expense for the three and nine months ended September 30, 20172018 compared to the same periods in 2016,2017, consisted of the following:
 Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
 Increase (Decrease)
 Increase (Decrease)
Baseline   
Labor, other benefits, contracting and materials$3
 $3
Storm-related costs(2) 4
Uncollectible accounts expense(2) (7)
Remeasurement of AMI-related regulatory asset(a)
(1) (2)
  Deferral of merger-related costs to regulatory asset—
 (6)
BSC and PHISCO allocations(b)
(1) (15)
Merger commitments(c)
27
 (79)
Other2
 (5)
 26
 (107)
Regulatory required programs   
Purchased power administrative costs(2) (4)
Total increase (decrease)$24
 $(111)
 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
ARO update(a)
22
 22
Merger costs(b)
8
 14
Labor and contracting(c)
(2) 3
Other6
 9
 34
 48
    
Regulatory required programs(1) (1)
Total increase$33
 $47
_________
(a)RelatedReflects an increase primarily related to a remeasurementasbestos identified at the Buzzard Point property. See Note 13 - Asset Retirement Obligations of a regulatory assetthe Combined Notes to Consolidated Financial Statements for legacy meters recognized in 2016.additional information.
(b)Primarily relateddue to a deferral of accumulated merger severance and compensationintegration costs recognizedas regulatory assets in 2016.2017.
(c)Primarily related to merger-related commitments for customer rate creditsIncludes additional costs associated with mutual assistance programs. An equal and charitable contributionsoffsetting increase has been recognized in 2016.Operating revenues for the period presented.

244
Table of Contents


Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 20172018 compared to the same periodsperiod in 20162017, consisted of the following:
Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
Increase (Decrease)
 Increase (Decrease)
Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$3
 $9
$3
 $8
Regulatory asset amortization(b)—
 (2)10
 16
Regulatory required programs(b)


(2) (3)
Regulatory required programs(c)
4
 20
Total increase$1
 $4
$17
 $44
_________
(a)Depreciation expense increased due to higher depreciation rates in Maryland effective February 2017 and due to ongoing capital expenditures.
(b)Regulatory asset amortization increased primarily due to additional regulatory assets related to rate case activity.
(c)Regulatory required programs increased as a result of higher amortization of the DC PLUG regulatory asset. Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. A partiallyAn equal and offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.revenues.
Taxes Other Than Income
Taxes other than income for the three andmonths ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Taxes other than income for the nine months ended September 30, 20172018 compared to the same periodsperiod in 2016 remained relatively constant.2017, increased due to an increase in the utility taxes that are collected and passed through by Pepco (which is substantially offset in Operating revenues).

Table of Contents

Gain on Sales of Assets
The decrease in Gain on sales of assets during the nine months ended September 30, 2018, compared to the same period in 2017, is primarily due to the sale of land in June 2017.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 20172018 compared to the same periods in 2016 remained relatively constant.2017 increased due to higher outstanding debt.
Other, Net
Other, net for the three and nine months ended September 30, 20172018 compared to the same periods in 20162017 remained relatively constant.consistent.
Effective Income Tax Rate
DPL'sPepco's effective income tax rate was 38.0%(2.3)% and 30.2%30.4% for the three months ended September 30, 2018 and 2017, and 2016, respectively. DPL'sThe decrease in the effective income tax rate for the three months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA.
Pepco's effective income tax rate was 28.7%3.9% and 900.0%23.3% for the nine months ended September 30, 2018 and 2017, and 2016, respectively. In the first quarter of 2017, DPL decreased its liability for unrecognized tax benefits by $16 million resulting in a benefit to Income taxes and a correspondingThe decrease in itsthe effective income tax rate. rate for the nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA, partially offset by a nonrecurring adjustment to income tax reserve balances in 2017.
See Note 12 -— Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
DPL

Table of Contents

Pepco Electric Operating Statistics and Revenue Detail
 Three Months Ended  
 September 30,		 % Change Weather - Normal % Change Nine Months Ended 
 September 30,		 % Change Weather - Normal % Change
Retail Deliveries to Customers (in GWhs)2017 2016   2017 2016  
Retail Deliveries(a)
               
Residential1,439
 1,601
 (10.1)% (2.2)% 3,843
 4,066
 (5.5)% 0.4 %
Small commercial & industrial636
 642
 (0.9)% 3.2 % 1,693
 1,746
 (3.0)% (0.9)%
Large commercial & industrial1,245
 1,250
 (0.4)% 4.1 % 3,440
 3,492
 (1.5)% 0.3 %
Public authorities & electric railroads10
 9
 11.1 % 11.1 % 35
 35
 — % — %
Total retail deliveries3,330
 3,502
 (4.9)% 1.2 % 9,011
 9,339
 (3.5)% 0.1 %

245
Table of Contents


Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		   Weather - Normal % Change Nine Months Ended
September 30,		   Weather - Normal % Change
2018 2017 % Change  2018 2017 % Change 
Retail Deliveries(a)
               
Residential2,446
 2,281
 7.2 % 1.4 % 6,528
 6,038
 8.1 % 0.1 %
Small commercial & industrial327
 347
 (5.8)% (8.1)% 982
 999
 (1.7)% (4.8)%
Large commercial & industrial4,298

4,146
 3.7 % 1.3 % 11,661
 11,306
 3.1 % 1.0 %
Public authorities & electric railroads181
 180
 0.6 % — % 531
 542
 (2.0)% (2.6)%
Total retail deliveries7,252
 6,954
 4.3 % 0.8 % 19,702
 18,885
 4.3 % 0.3 %
 As of September 30,
Number of Electric Customers2017 2016
Residential458,790
 455,640
Small commercial & industrial60,542
 60,034
Large commercial & industrial

1,406
 1,414
Public authorities & electric railroads633
 643
Total521,371
 517,731
 Three Months Ended  
 September 30,		 % Change Nine Months Ended 
 September 30,		 % Change
Electric Revenue2017 2016  2017 2016 
Retail Sales(a)
           
Residential$183
 $200
 (8.5)% $508
 $522
 (2.7)%
Small commercial & industrial49
 48
 2.1 % 138
 143
 (3.5)%
Large commercial & industrial26
 24
 8.3 % 77
 74
 4.1 %
Public authorities & electric railroads3
 2
 50.0 % 11
 9
 22.2 %
Total retail261
 274
 (4.7)% 734
 748
 (1.9)%
Other revenue(b)
48
 40
 20.0 % 132
 124
 6.5 %
Total electric revenue(c)
$309
 $314
 (1.6)% $866
 $872
 (0.7)%
 As of September 30,
Number of Electric Customers2018 2017
Residential802,607
 790,032
Small commercial & industrial53,700
 53,543
Large commercial & industrial21,927
 21,733
Public authorities & electric railroads147
 143
Total878,381
 865,451
_________
(a)Reflects delivery volumes and revenues from customers purchasing electricity directly from DPLPepco 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 $2 million for the three months ended September 30, 2017 and 2016 and $6 million for the nine months ended September 30, 2017 and 2016.
DPL Natural Gas Operating Statistics and Revenue DetailSee Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
 Three Months Ended  
 September 30,		 % Change Weather - Normal % Change Nine Months Ended 
 September 30,		 % Change Weather - Normal % Change
Retail Deliveries to Customers (in mmcf)2017 2016   2017 2016  
Retail Deliveries               
Retail sales1,069
 1,121
 (4.6)% (6.4)% 8,679
 9,253
 (6.2)% 6.5%
Transportation & other1,197
 1,166
 2.7 % 2.4 % 4,690
 4,455
 5.3 % 7.9%
Total natural gas deliveries2,266
 2,287
 (0.9)% (2.0)% 13,369
 13,708
 (2.5)% 7.0%
 As of September 30,
Number of Gas Customers2017 2016
Residential121,238
 120,075
Commercial & industrial9,700
 9,656
Transportation & other155
 157
Total131,093
 129,888

246
Table of Contents


 Three Months Ended  
 September 30,		 % Change Nine Months Ended 
 September 30,		 % Change
Natural Gas Revenue2017 2016  2017 2016 
Retail Sales(a)
           
Retail sales$12
 $13
 (7.7)% $87
 $87
 —%
Transportation & other(b)
6
 4
 50.0 % 18
 15
 20.0%
Total natural gas revenues$18
 $17
 5.9 % $105
 $102
 2.9%
__________
(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.

247
Table of Contents


Results of Operations - ACE
 Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
 2017 2016  2017 2016 
Operating revenues$370
 $421
 $(51) $915
 $982
 $(67)
Purchased power expense176
 221
 45
 442
 520
 78
Revenues net of purchased power expense(a)
194
 200
 (6) 473
 462
 11
Other operating expenses    
     
Operating and maintenance72
 67
 (5) 225
 346
 121
Depreciation and amortization41
 49
 8
 113
 130
 17
Taxes other than income2
 1
 (1) 6
 6
 —
Total other operating expenses115
 117
 2
 344
 482
 138
Gain on sales of assets—
 —
 —
 —
 1
 (1)
Operating income (loss)79
 83
 (4) 129
 (19) 148
Other income and (deductions)    
     
Interest expense, net(15) (15) —
 (46) (47) 1
Other, net1
 2
 (1) 6
 8
 (2)
Total other income and (deductions)(14)
(13) (1) (40)
(39) (1)
Income (loss) before income taxes65

70
 (5) 89

(58) 147
Income taxes24
 23
 (1) 12
 (8) (20)
Net income (loss)$41
 $47
 $(6) $77
 $(50) $127
_________
(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 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 (Loss)
Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. ACE's Net income for the three months ended September 30, 2017, was lower than the same period in 2016, primarily due to a decrease in Revenue net of purchased power expense resulting from lower distribution revenues due to lower average customer usage and unfavorable weather related sales, partially offset by the impact of distribution rate increases approved by the NJBPU effective August 2016.
Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. ACE's Net income (loss) for the nine months ended September 30, 2017, was higher than the same period in 2016, primarily due to an increase in Revenue net of purchased power expense resulting from higher electric distribution revenues as a result of a distribution rate increase approved by the NJBPU effective August 2016, lower Operating and maintenance expense mostly due to merger-related costs recognized in March 2016 and a decrease in income tax reserves in the first quarter 2017 for uncertain tax positions related to the deductibility of certain merger commitments.
Revenues Net of Purchased Power Expense
There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC, and ZEC procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity, REC, and ZEC procurement costs from retail customers without mark-up. Therefore, fluctuations in these costs have no impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Exelon 2017 Form 10-K 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 three and nine months ended September 30, 2018 and 2017, consisted of the following:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric67% 68% 68% 70%
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2018 and 2017 consisted of the following:
 September 30, 2018 September 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric1,367,700
 34% 1,360,800
 34%
The changes in ComEd’s Revenue net of purchased power expense for the three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Electric distribution revenue$(59) $(126)
Transmission revenue(16) (32)
Energy efficiency revenue(a)
14
 31
Regulatory required programs(a)
(1) (95)
Uncollectible accounts recovery, net2
 5
Other(3) 37
Total decrease$(63) $(180)
_________
(a)Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

Table of Contents

Revenue Decoupling. The demand for electricity is affected by weather conditions. Under FEJA, ComEd revised its electric distribution rate formula effective January 1, 2017 to eliminate the favorable and unfavorable impacts on Operating revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage 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 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 three and nine months ended September 30, 2018 and 2017, consisted of the following:
Heating and Cooling Degree-Days      % Change
Three Months Ended September 30,2018 2017 Normal2018 vs. 2017 2018 vs. Normal
Heating Degree-Days56
 42
 97
 33.3% (42.3)%
Cooling Degree-Days895
 699
 641
 28.0% 39.6 %
          
Nine Months Ended September 30,         
Heating Degree-Days3,993
 3,269
 3,972
 22.1% 0.5 %
Cooling Degree-Days1,259
 962
 882
 30.9% 42.7 %
Electric Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. 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. Electric distribution revenue decreased during the three and nine months ended September 30, 2018, primarily due to the impact of the lower federal income tax rate, partially offset by increased revenues due to higher rate base and increased depreciation expense as compared to the same period in 2017. See Depreciation and amortization expense discussions below and Note 6 — Regulatory Matters and Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. For the three months ended September 30, 2018, ComEd recorded decreased transmission revenue primarily due to the impact of the lower federal income tax rate, partially offset by increased revenues due to higher rate base and increased depreciation expense as compared to the same period in 2017. For the nine months ended September 30, 2018, ComEd recorded decreased transmission revenue primarily due to the decreased peak load and the impact of the lower federal income tax rate, partially offset by increased revenues due to higher rate base and increased depreciation expense as compared to the same period in 2017. See Operating and maintenance expense below and Note 6 — Regulatory Matters and Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue. Beginning June 1, 2017, FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual

Table of Contents

costs that the ICC determines are prudently and reasonably incurred in a given year.  Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE 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. See Depreciation and amortization expense discussions below and Note 6 — 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 rate riders to recover costs incurred for regulatory programs such as ComEd’s purchased power administrative costs and energy efficiency and demand response through June 1, 2017 pursuant to FEJA. The riders are designed to provide full and current cost recovery. 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.
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. The increase in Other revenue for the nine months ended September 30, 2018 compared to the same period in 2017 primarily reflects mutual assistance revenues associated with hurricane and winter storm restoration efforts. An equal and offsetting amount has been included in Operating and maintenance expense and Taxes other than income.
Operating and Maintenance Expense
 Three Months Ended
September 30,		 
Increase
(Decrease)
 Nine Months Ended
September 30,		 Increase (Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense — baseline$336
 $344
 $(8) $973
 $1,000
 $(27)
Operating and maintenance expense — regulatory required programs(a)
1
 2
 $(1) 1
 96
 (95)
Total Operating and maintenance expense$337

$346

$(9)
$974

$1,096

$(122)
_________
(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.

Table of Contents

The decrease in Operating and maintenance expense for the three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor, other benefits, contracting and materials(a)
$(1) $(3)
Pension and non-pension postretirement benefits expense(a)
(1) (1)
Storm-related costs(5) (21)
Uncollectible accounts expense — provision(b)
7
 11
Uncollectible accounts expense — recovery, net(b)
(5) (6)
BSC costs(a)
(9) (8)
Other(a)
6
 1
 (8) (27)
Regulatory required programs   
Energy efficiency and demand response programs(c)
(1) (95)
Decrease in operating and maintenance expense$(9) $(122)
_________
(a)Includes additional costs associated with mutual assistance programs. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
(b)ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. During the three and nine months ended September 30, 2018, ComEd recorded a net increase in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
(c)Beginning June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.
Depreciation and Amortization Expense
The increase in Depreciation and amortization expense during the three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase Increase
Depreciation expense(a)
$9
 $30
Regulatory asset amortization(b)
16
 35
Total increase$25
 $65
_________
(a)Primarily reflects ongoing capital expenditures for the three and nine months ended September 30, 2018.
(b)Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset.
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.

Table of Contents

Gain on Sales of Assets
The increase in Gain on sales of assets during the nine months ended September 30, 2018 compared to the same period in 2017, is primarily due to the sale of land in March 2018.
Interest Expense, Net
The changes in Interest expense, net, for the three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Interest expense related to uncertain tax positions(a)
$—
 $(13)
Interest expense on debt (including financing trusts)(2) 2
Other(2) (3)
Total decrease$(4) $(14)
__________
(a)Primarily reflects additional interest recorded in the second quarter of 2017 related to Exelon's like-kind exchange tax position.
Other, Net
Other, net, remained relatively consistent for the three and nine months ended September 30, 2018 compared to the same period in 2017.
Effective Income Tax Rate
ComEd's effective income tax rate was 21.2% and 40.9% for the three months ended September 30, 2018 and 2017, respectively. ComEd's effective income tax rate was 21.1% and 42.3% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

ComEd Electric Operating Statistics Detail
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		 % Change 
Weather-
Normal
% Change
 Nine Months Ended
September 30,		 % Change 
Weather-
Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential8,845
 8,004
 10.5 % (1.5)% 22,019
 20,164
 9.2% 0.1%
Small commercial & industrial8,626
 8,488
 1.6 % (1.0)% 24,204
 23,634
 2.4% —%
Large commercial & industrial7,450
 7,232
 3.0 % 1.1 % 21,398
 20,712
 3.3% 1.6%
Public authorities & electric railroads301
 302
 (0.3)% (0.5)% 947
 928
 2.0% 1.2%
Total retail deliveries25,222

24,026
 5.0 % (0.5)% 68,568

65,438
 4.8% 0.6%
 As of September 30,
Number of Electric Customers2018 2017
Residential3,635,678
 3,610,091
Small commercial & industrial380,529
 376,309
Large commercial & industrial1,994
 1,954
Public authorities & electric railroads4,767
 4,763
Total4,022,968

3,993,117
_________
(a)Reflects delivery 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.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

Table of Contents

Results of Operations — PECO
 Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$757
 $715
 $42
 $2,275
 $2,141
 $134
Purchased power and fuel expense263
 235
 (28) 818
 719
 (99)
Revenues net of purchased power and fuel expense(a)
494
 480
 14
 1,457
 1,422
 35
Other operating expenses           
Operating and maintenance219
 197
 (22) 686
 595
 (91)
Depreciation and amortization75
 72
 (3) 224
 213
 (11)
Taxes other than income46
 42
 (4) 125
 116
 (9)
Total other operating expenses340
 311
 (29) 1,035
 924
 (111)
Gain on sales of assets—
 —
 —
 1
 —
 1
Operating income154
 169
 (15) 423
 498
 (75)
Other income and (deductions)           
Interest expense, net(32) (31) (1) (96) (93) (3)
Other, net2
 2
 —
 4
 6
 (2)
Total other income and (deductions)(30) (29) (1) (92) (87) (5)
Income before income taxes124
 140
 (16) 331
 411
 (80)
Income taxes(2) 28
 30
 (5) 84
 89
Net income$126
 $112
 $14
 $336
 $327
 $9
_________
(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 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 presentations 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
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017.PECO's Net income increased from the same period in 2017, primarily due to higher Operating revenues net of purchase power and fuel expense attributable to favorable weather and volume. The TCJA did not significantly impact PECO's Net income for the three and nine months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the requirement to pass back the tax savings through customer rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.PECO's Net income increased from the same period in 2017, primarily due to higher Operating revenues net of purchase power and fuel expense attributable to favorable weather and volume, partially offset by higher Operating and maintenance expense attributable to increased storm restoration costs as a result of winter storms in March 2018. The TCJA did not significantly impact PECO's Net income for the three and nine months ended September 30, 2018 as the favorable income tax impacts were

Table of Contents

predominantly offset by lower revenues resulting from the requirement to pass back the tax savings through customer rates.
Revenues Net of Purchased Power and Fuel Expense
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 revenue 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 revenues net of purchased 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 three and nine months ended September 30, 2018 and 2017, consisted of the following:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric68% 70% 69% 71%
Natural Gas31% 29% 26% 26%
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2018 and 2017 consisted of the following:
 September 30, 2018 September 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric536,000
 33% 570,500
 35%
Natural Gas88,900
 17% 82,600
 16%

Table of Contents

The changes in PECO’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
 Electric Natural Gas Total Electric Natural Gas Total
Weather$20
 $1
 $21
 $39
 $19
 $58
Volume17
 (1) 16
 26
 2
 28
Pricing(36) 3
 (33) (66) (5) (71)
Regulatory required programs7
 —
 7
 5
 —
 5
Other3
 —
 3
 18
 (3) 15
Total increase$11
 $3
 $14
 $22
 $13
 $35
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2018 compared to the same period in 2017, Operating revenue net of purchased power and fuel increased due to favorable weather conditions.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and nine months ended September 30, 2018 compared to the same period in 2017 and normal weather consisted of the following:
Heating and Cooling Degree-Days  Normal % Change
Three Months Ended September 30,2018 2017From 2017 2018 vs. Normal
Heating Degree-Days13
 14
 27
 (7.1)% (51.9)%
Cooling Degree-Days1,124
 989
 999
 13.7 % 12.5 %
          
Nine Months Ended September 30,         
Heating Degree-Days2,892
 2,437
 2,912
 18.7 % (0.7)%
Cooling Degree-Days1,506
 1,404
 1,383
 7.3 % 8.9 %
Volume. Operating revenue net of purchased power related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2018 compared to the same period in 2017, increased due to the impact of moderate economic and customer growth partially offset by the impact of energy efficiency initiatives on customer usages primarily in the residential class. Additionally, the increase represents a shift in the volume profile across classes from the commercial and industrial classes to the residential class.
Pricing.Operating revenues net of purchased power as a result of pricing for the three and nine months ended September 30, 2018 and operating revenues net of fuel as the result of pricing for the nine months ended September 30, 2018 compared to the same periods in 2017 decreased primarily due to the pass back through customers rates the tax savings associated with the lower federal income

Table of Contents

tax rate. See Note 6 — 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 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. See 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
 Three Months Ended
September 30,		 
Increase
(Decrease)
 Nine Months Ended
September 30,		 Increase
(Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense — baseline$198
 $183
 $15
 $632
 $552
 $80
Operating and maintenance expense — regulatory required programs(a)
21
 14
 7
 54
 43
 11
Total Operating and maintenance expense$219
 $197
 $22
 $686
 $595
 $91
_________
(a)Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
The changes in Operating and maintenance expense for the three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor, other benefits, contracting and materials$(1) $10
Storm-related costs(a)
2
 61
Pension and non-pension postretirement benefits expense(2) (5)
Uncollectible accounts expense6
 8
Other10
 6
 15
 80
Regulatory Required Programs   
Energy efficiency7
 11
Total increase$22
 $91
__________
(a)Reflects increased costs incurred from the Q1 2018 winter storms.

Table of Contents

Depreciation and Amortization Expense
Depreciation and amortization expense increased primarily due to ongoing capital spend for the three and nine months ended September 30, 2018 compared to the same period in 2017.
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income increased for the three and nine months ended September 30, 2018 compared to the same period in 2017 due to an increase in gross receipts tax driven by an increase in electric revenue.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2018 remained relatively consistent compared to the same period in 2017.
Other, Net
Other, net for the three and nine months ended September 30, 2018 remained consistent compared to the same period in 2017.
Effective Income Tax Rate
PECO's effective income tax rate was (1.6)% and 20.0% for the three months ended September 30, 2018 and 2017, respectively. PECO's effective income tax rate was (1.5)% and 20.4% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

PECO Electric Operating Statistics
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		 % Change 
Weather -
Normal
% Change
 Nine Months Ended
September 30,		 % Change Weather -
Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential4,166
 3,752
 11.0 % 4.7 % 10,741
 9,939
 8.1 % 2.8 %
Small commercial & industrial2,315
 2,158
 7.3 % 2.0 % 6,273
 6,048
 3.7 % 0.4 %
Large commercial & industrial4,378
 4,137
 5.8 % 4.9 % 11,892
 11,593
 2.6 % 2.5 %
Public authorities & electric railroads189
 198
 (4.5)% (4.8)% 568
 618
 (8.1)% (7.7)%
Total retail deliveries11,048

10,245
 7.8 % 4.0 % 29,474

28,198
 4.5 % 1.9 %
 As of September 30,
Number of Electric Customers2018 2017
Residential1,476,914
 1,463,906
Small commercial & industrial152,253
 150,964
Large commercial & industrial3,124
 3,112
Public authorities & electric railroads9,561
 9,665
Total1,641,852
 1,627,647
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

Table of Contents

PECO Natural Gas Operating Statistics
Deliveries to Customers (in mmcf)Three Months Ended
September 30,		 % Change 
Weather -
 Normal
% Change
 Nine Months Ended
September 30,		 % Change 
Weather -
 Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential2,099
 2,177
 (3.6)% 0.9% 28,562
 24,866
 14.9% 0.2 %
Small commercial & industrial1,776
 1,814
 (2.1)% 0.2% 15,792
 13,944
 13.3% 1.0 %
Large commercial & industrial6
 2
 200.0 % 12.8% 58
 15
 286.7% 278.3 %
Transportation5,693
 5,674
 0.3 % 3.2% 19,242
 19,122
 0.6% (3.8)%
Total natural gas deliveries9,574
 9,667
 (1.0)% 1.6% 63,654
 57,947
 9.8% (0.8)%
 As of September 30,
Number of Natural Gas Customers2018 2017
Residential479,732
 474,766
Small commercial & industrial43,638
 43,352
Large commercial & industrial1
 6
Transportation761
 771
Total524,132

518,895
_________
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

Table of Contents

Results of Operations — BGE
 Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$731
 $738
 $(7) $2,369
 $2,363
 $6
Purchased power and fuel expense272
 269
 (3) 881
 853
 (28)
Revenues net of purchased power and fuel expense(a)
459
 469
 (10) 1,488
 1,510
 (22)
Other operating expenses           
Operating and maintenance182
 175
 (7) 578
 532
 (46)
Depreciation and amortization110
 109
 (1) 358
 348
 (10)
Taxes other than income64
 61
 (3) 188
 180
 (8)
Total other operating expenses356
 345
 (11) 1,124
 1,060
 (64)
Gain on sales of assets—
 —
 —
 1
 —
 1
Operating income103
 124
 (21) 365
 450
 (85)
Other income and (deductions)           
Interest expense, net(27) (26) (1) (78) (80) 2
Other, net5
 4
 1
 14
 12
 2
Total other income and (deductions)(22) (22) —
 (64) (68) 4
Income before income taxes81
 102
 (21) 301
 382
 (81)
Income taxes18
 40
 22
 59
 151
 92
Net income$63
 $62
 $1
 $242
 $231
 $11
_________
(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
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017. BGE’s Net income for the three months ended September 30, 2018 was relatively consistent with the same period in 2017. The TCJA did not significantly impact BGE's net income for the three months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017. BGE’s Net income for the nine months ended September 30, 2018 was higher than the same period in 2017, due primarily to higher transmission revenues, partially offset by an increase in Operating and maintenance expense attributable to increased storm restoration costs as a result of storms in March 2018 and September 2018. The TCJA did not significantly impact BGE's net income for the nine months ended September 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.

Table of Contents

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. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on 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 the number of customers electing to use a competitive supplier for electricity and/or natural gas. All BGE customers have the choice to purchase electricity and natural gas from competitive suppliers. The customers' choice of suppliers does not impact the volume of deliveries but does affect revenue collected from customers related to supplied electricity and natural gas.
Retail deliveries purchased from competitive electricity and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30, 2018 and 2017 consisted of the following:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric59% 60% 59% 60%
Natural Gas76% 74% 56% 57%
The number of retail customers purchasing electricity and natural gas from competitive suppliers at September 30, 2018 and 2017 consisted of the following:
 September 30, 2018 September 30, 2017
 Number of Customers % of total retail customers Number of customers % of total retail customers
Electric335,200
 26% 339,300
 27%
Natural Gas147,400
 22% 148,600
 22%

Table of Contents

The changes in BGE’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2018, compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
 Electric Gas Total Electric Gas Total
Distribution revenue$(17) $(2) $(19) $(48) $(19) $(67)
Regulatory required programs1
 (1) —
 3
 2
 5
Transmission revenue6
 —
 6
 23
 —
 23
Other, net—
 3
 3
 6
 11
 17
Total decrease$(10) $—
 $(10) $(16) $(6) $(22)
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 fluctuations in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved distribution charges 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 volatility in 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 three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
Heating and Cooling Degree-Days      % Change
Three Months Ended September 30,2018 2017 Normal 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days31
 64
 76
 (51.6)% (59.2)%
Cooling Degree-Days733
 595
 601
 23.2 % 22.0 %
          
Nine Months Ended September 30,         
Heating Degree-Days2,969
 2,524
 2,974
 17.6 % (0.2)%
Cooling Degree-Days1,032
 877
 857
 17.7 % 20.4 %
Distribution Revenue. The decrease in distribution revenues for the three and nine months ended September 30, 2018, compared to the same period in 2017, was primarily due to the impact of reduced distribution rates to reflect the lower federal income tax rate. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Table of Contents

Regulatory Required Programs. Revenue from regulatory required programs are billings for the costs of various legislative and/or regulatory programs that are recoverable from customers on a full and current basis. These programs are designed to provide full cost recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income 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 rate adjustments to reflect fluctuations in the underlying costs, capital investments being recovered and other billing determinants. The increase in transmission revenue for the three and nine months ended September 30, 2018, compared to the same period in 2017, was primarily due to increases in capital investment and operating and maintenance expense recoveries. See Operating and Maintenance Expense below and Note 6 — 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, primarily includes assistance provided to other utilities through BGE's mutual assistance program, service application fees, and other miscellaneous revenue such as off-system sales and administrative charges.
Operating and Maintenance Expense
 Three Months Ended
September 30,		 
Increase
(Decrease)
 Nine Months Ended
September 30,		 Increase
(Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense — baseline$180
 $172
 $8
 $572
 $520
 $52
Operating and maintenance expense — regulatory required programs(a)
2
 3
 (1) 6
 12
 (6)
Total Operating and maintenance expense$182
 $175
 $7
 $578
 $532
 $46
_________
(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.

Table of Contents

The changes in Operating and maintenance expense for the three and nine months ended September 30, 2018, compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Storm-related costs(a)
$5
 $36
Labor, other benefits, contracting and materials1
 2
Uncollectible accounts expense1
 3
BSC costs(1) 4
Other2
 7
 8
 52
Regulatory Required Programs   
Other(1) (6)
Total increase$7
 $46
__________
(a)Reflects increased storm restoration costs incurred from storms in Q1 2018 and Q3 2018.
Depreciation and Amortization
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2018, compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$8
 $17
Regulatory asset amortization(b)
(8) (18)
Regulatory required programs(c)
1
 11
Total increase$1
 $10
_________
(a)Depreciation expense increased due to ongoing capital expenditures.
(b)Regulatory asset amortization decreased for the three and nine months ended September 30, 2018 compared to the same period in 2017 primarily due to certain regulatory assets that became fully amortized as of December 31, 2017. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(c)Depreciation and amortization expenses for regulatory required programs 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.
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 2018, compared to the same period in 2017, increased primarily due to an increase in property taxes.
Gain on Sales of Assets
Gain on sales of assets, for the three months ended September 30, 2018 compared to the same period in 2017, remained relatively consistent. The increase in Gain on sales of assets during the nine

Table of Contents

months ended September 30, 2018, compared to the same period in 2017, is due to the sale of land in June 2018.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2018, compared to the same period in 2017, remained relatively consistent.
Other, Net
Other, net for the three and nine months ended September 30, 2018, compared to the same period in 2017, remained relatively consistent.
Effective Income Tax Rate
BGE’s effective income tax rate was 22.2% and 39.2% for the three months ended September 30, 2018 and 2017, respectively. BGE's effective income tax rate was 19.6% and 39.5% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and nine months ended September 30, 2018, compared to the same periods in 2017, is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — 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 Detail
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		 % Change Weather -
Normal
% Change		 Nine Months Ended
September 30,		 % Change Weather -
Normal
% Change
2018
2017  2018 2017 
Retail Deliveries(a)
               
Residential3,663
 3,370
 8.7% 1.8 % 9,960
 9,126
 9.1 % 1.8 %
Small commercial & industrial825
 785
 5.1% (1.1)% 2,309
 2,210
 4.5 % (0.2)%
Large commercial & industrial3,909
 3,781
 3.4% 0.6 % 10,661
 10,422
 2.3 % (0.1)%
Public authorities & electric railroads64
 64
 —% (5.9)% 200
 204
 (2.0)% (4.1)%
Total electric deliveries8,461
 8,000
 5.8% 0.9 % 23,130
 21,962
 5.3 % 0.7 %
 As of September 30,
Number of Electric Customers2018 2017
Residential1,165,012
 1,156,659
Small commercial & industrial114,082
 113,224
Large commercial & industrial12,218
 12,144
Public authorities & electric railroads263
 274
Total1,291,575
 1,282,301
_________
(a)Reflects delivery 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.

Table of Contents

BGE Natural Gas Operating Statistics and Detail
Deliveries to Customers (in mmcf)Three Months Ended
September 30,		 % Change Weather -
Normal
% Change		 Nine Months Ended
September 30,		 % Change Weather -
Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential2,244
 2,395
 (6.3)% (4.5)% 29,290
 24,125
 21.4% 3.2%
Small commercial & industrial813
 814
 (0.1)% 0.4 % 7,020
 5,667
 23.9% 7.2%
Large commercial & industrial8,227
 8,012
 2.7 % 2.2 % 34,044
 30,828
 10.4% 5.9%
Other(b)
3,144
 68
 4,523.5 % n/a
 11,183
 2,463
 354.0% n/a
Total natural gas deliveries14,428
 11,289
 27.8 % 0.6 % 81,537
 63,083
 29.3% 4.9%
 As of September 30,
Number of Gas Customers2018
2017
Residential631,589
 626,039
Small commercial & industrial38,175
 38,141
Large commercial & industrial5,920
 5,832
Total675,684

670,012
_________
(a)Reflects delivery volumes 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.
(b)Other natural gas revenue includes off-system sales of 3,144 mmcfs and 68 mmcfs for the three months ended September 30, 2018 and 2017, respectively. Other natural gas revenue includes off-system sales of 11,183 mmcfs and 2,463 mmcfs for the nine months ended September 30, 2018 and 2017. respectively.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

Table of Contents

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. 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.
 Three Months Ended
September 30,		 Favorable (Unfavorable) Variance Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$1,361
 $1,310
 $51
 $3,688
 $3,557
 $131
Purchased power and fuel expense509
 473
 (36) 1,410
 1,318
 (92)
Revenues net of purchased power and fuel expense(a)
852
 837
 15
 2,278
 2,239
 39
Other operating expenses           
Operating and maintenance292
 251
 (41) 857
 774
 (83)
Depreciation and amortization192
 179
 (13) 555
 511
 (44)
Taxes other than income123
 122
 (1) 343
 344
 1
Total other operating expenses607
 552
 (55) 1,755
 1,629
 (126)
Gain on sales of assets—
 —
 —
 —
 1
 (1)
Operating income245
 285
 (40) 523
 611
 (88)
Other income and (deductions)           
Interest expense, net(65) (62) (3) (193) (183) (10)
Other, net11
 13
 (2) 33
 40
 (7)
Total other income and (deductions)(54) (49) (5) (160) (143) (17)
Income before income taxes191
 236
 (45) 363
 468
 (105)
Income taxes4
 83
 79
 28
 109
 81
Equity in earnings of unconsolidated affiliate—
 —
 —
 1
 —
 1
Net income$187
 $153
 $34
 $336
 $359
 $(23)
_________
(a)PHI evaluates its operating performance using the measure of revenue net of purchased power and fuel expense for electric and natural gas sales. PHI believes revenue net of purchased power and fuel 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 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.
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017.PHI's Net income for the three months ended September 30, 2018 was $187 million compared to $153 million for the three months ended September 30, 2017.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $15 million for the three months ended September 30, 2018 compared to the same period in 2017 primarily due to higher utility revenues due to distribution rate increases at Pepco, DPL, and ACE, as well as favorable weather and volume, partially offset by lower revenues resulting from the pass back of TCJA tax savings through customer rates.

Table of Contents

Operating and maintenance expense increased by $41 million for the three months ended September 30, 2018 compared to the same period in 2017. The increase is primarily due to the following factors:
Increase of $22 million at Pepco due to a charge associated with a remeasurement of the Buzzard Point ARO; and
Increase of $14 million primarily due to deferral of accumulated merger integration costs as regulatory assets in 2017.
Depreciation and amortization expense for the three months ended September 30, 2018 compared to the same period in 2017 increased by $13 million primarily due to ongoing capital expenditures as well as increased amortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues).
Taxes other than income for the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Gain on sales of assets during the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Interest expense, net for the three months ended September 30, 2018 compared to the same period in 2017 increased by $3 million due to higher outstanding debt.
Other, net for the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Equity in earnings for the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
PHI's effective income tax rate was 2.1% and 35.2% for the three months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.PHI's Net income for the nine months ended September 30, 2018 was $336 million compared to $359 million for the nine months ended September 30, 2017.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $39 million for the nine months ended September 30, 2018 compared to the same period in 2017 primarily due to higher utility revenues due to distribution rate increases at Pepco, DPL, and ACE, as well as favorable weather and volume, partially offset by lower revenues resulting from the pass back of TCJA tax savings through customer rates.

Table of Contents

Operating and maintenance expense increased by $83 million for the nine months ended September 30, 2018 compared to the same period in 2017. The increase is primarily due to the following factors:
Increase of $28 million primarily due to deferral of accumulated merger integration costs as regulatory assets in 2017;
Net increase of $23 million in labor and contracting expense due to an increase of $32 million at Pepco, DPL and ACE partially offset by a decrease of $9 million at PHISCO as a result of the completion of integration transition activities; and
Increase of $22 million at Pepco due to a charge associated with a remeasurement of the Buzzard Point ARO.
Depreciation and amortization expense for the nine months ended September 30, 2018 compared to the same period in 2017 increased by $44 million primarily due to ongoing capital expenditures as well as increased amortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues).
Taxes other than income for the nine months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Gain on sales of assets during the nine months ended September 30, 2018 compared to the same period in 2017 decreased $1 million due to the sale of land in June 2017.
Interest expense, net for the nine months ended September 30, 2018 compared to the same period in 2017 increased $10 million due to higher outstanding debt.
Other, net for the nine months ended September 30, 2018 compared to the same period in 2017 decreased $7 million primarily due to lower income from AFUDC equity.
Equity in earnings for the nine months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
PHI's effective income tax rate was 7.7% and 23.3% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA, partially offset by a nonrecurring adjustment to income tax reserve balances in 2017. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

Results of Operations - Pepco
 Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2018 2017  2018 2017 
Operating revenues$628
 $604
 $24
 $1,708
 $1,649
 $59
Purchased power expense177
 168
 (9) 497
 478
 (19)
Revenues net of purchased power expense(a)
451
 436
 15
 1,211
 1,171
 40
Other operating expenses           
Operating and maintenance136
 103
 (33) 383
 336
 (47)
Depreciation and amortization99
 82
 (17) 286
 242
 (44)
Taxes other than income104
 102
 (2) 288
 282
 (6)
Total other operating expenses339
 287
 (52) 957
 860
 (97)
Gain on sales of assets—
 —
 —
 —
 1
 (1)
Operating income112
 149
 (37) 254
 312
 (58)
Other income and (deductions)    
     
Interest expense, net(32) (31) (1) (96) (89) (7)
Other, net7
 7
 —
 23
 22
 1
Total other income and (deductions)(25) (24) (1) (73) (67) (6)
Income before income taxes87
 125
 (38) 181
 245
 (64)
Income taxes(2) 38
 40
 7
 57
 50
Net income$89
 $87
 $2
 $174
 $188
 $(14)
_________
(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
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017.Pepco's Net income for the three months ended September 30, 2018, was relatively consistent with the same period in 2017. The TCJA did not significantly impact Pepco's Net income for the three months ended September 30, 2018 as the favorable tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.Pepco's Net income for the nine months ended September 30, 2018, was lower than the same period in 2017 primarily due to higher Operating and maintenance expense attributable to an increase in the asset retirement obligations related to the Buzzard Point property, deferral of accumulated merger integration costs as regulatory assets in 2017 and higher regulatory asset amortization due to additional regulatory assets related to rate case activity, partially offset by higher electric distribution base rates charged to customers in Maryland that became effective in October 2017 and June 2018 and higher electric distribution base rates charged to customers in the District of Columbia that became effective August 2017 and August 2018. The TCJA did not significantly impact Pepco's Net income for the nine

Table of Contents

months ended September 30, 2018 as the favorable tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
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. 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.
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 three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric64% 65% 64% 66%
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2018 and 2017 consisted of the following:
 September 30, 2018 September 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric175,838
 20% 179,106
 21%
Retail deliveries purchased from competitive electric generation suppliers represented 72% and 72% of Pepco’s retail kWh sales to the District of Columbia customers and 58% and 58% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2018, respectively and 72% and 73% of Pepco’s retail kWh sales to the District of Columbia customers and 60% and 60% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2017, respectively.

Table of Contents

The changes in Pepco’s operating revenues net of purchased power expense for the three and nine months ended September 30, 2018 compared to the same periods in 2017 consisted of the following:
 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
 Increase (Decrease) Increase (Decrease)
Volume$3
 $9
Distribution revenue6
 9
Regulatory required programs7
 27
Transmission revenue2
 (5)
Other(3) —
Total increase$15
 $40
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.
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 three and nine months ended September 30, 2018 compared to the same periods in 2017 and normal weather consisted of the following:
Heating and Cooling Degree-Days    % Change
Three Months Ended September 30,2018 2017 Normal 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days2
 8
 13
 (75.0)% (84.6)%
Cooling Degree-Days1,283
 1,130
 1,137
 13.5 % 12.8 %
       

 

Nine Months Ended September 30,      

 

Heating Degree-Days2,458
 1,963
 2,448
 25.2 % 0.4 %
Cooling Degree-Days1,861
 1,679
 1,626
 10.8 % 14.5 %
Volume. The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2018 compared to the same periods in 2017, primarily reflects the impact of residential customer growth.
Distribution Revenue. The increase in distribution revenues for the three and nine months ended September 30, 2018 compared to the same periods in 2017 was primarily due to higher electric distribution base rates charged to customers in Maryland that became effective in October 2017 and June 2018 and higher electric distribution base rates charged to customers in the District of Columbia that became

Table of Contents

effective August 2017 and August 2018, partially offset by the impact of reduced distribution rates to reflect the lower federal income tax rate. See Note 6—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 Taxes other than income in Pepco's Consolidated Statements of Operations and Comprehensive Income. See Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs. Revenue from regulatory required programs increased for the three and nine months ended September 30, 2018 compared to the same periods in 2017 due to increases in the Maryland and District of Columbia surcharge rates and sales due to higher volumes, as well as the DC PLUG surcharge which became effective in February 2018.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, the highest daily peak load and other billing adjustments. The increase in transmission revenue for the three months ended September 30, 2018 compared to the same period in 2017 is a result of higher rates effective June 2018. The decrease in transmission revenue for the nine months ended September 30, 2018 is a result of a decrease in network transmission service peak loads, partially offset by higher rates effective June 2018.
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, and recoveries of other taxes.
Operating and Maintenance Expense
 Three Months Ended
September 30,		 Increase (Decrease) Nine Months Ended
September 30,		 
Increase
(Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense - baseline$133
 $99
 $34
 $374
 $326
 $48
Operating and maintenance expense - regulatory required programs(a)
3
 4
 (1) 9
 10
 (1)
Total operating and maintenance expense$136
 $103
 $33
 $383
 $336
 $47
_________
(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.

Table of Contents

The changes in Operating and maintenance expense for the three and nine months ended September 30, 2018 compared to the same periods in 2017, consisted of the following:
 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
ARO update(a)
22
 22
Merger costs(b)
8
 14
Labor and contracting(c)
(2) 3
Other6
 9
 34
 48
    
Regulatory required programs(1) (1)
Total increase$33
 $47
_________
(a)Reflects an increase primarily related to asbestos identified at the Buzzard Point property. See Note 13 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
(b)Primarily due to a deferral of accumulated merger integration costs as regulatory assets in 2017.
(c)Includes additional costs associated with mutual assistance programs. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
 Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$3
 $8
Regulatory asset amortization(b)
10
 16
Regulatory required programs(c)
4
 20
Total increase$17
 $44
_________
(a)Depreciation expense increased due to ongoing capital expenditures.
(b)Regulatory asset amortization increased primarily due to additional regulatory assets related to rate case activity.
(c)Regulatory required programs increased as a result of higher amortization of the DC PLUG regulatory asset. Depreciation and amortization expenses for regulatory required programs 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.
Taxes Other Than Income
Taxes other than income for the three months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Taxes other than income for the nine months ended September 30, 2018 compared to the same period in 2017, increased due to an increase in the utility taxes that are collected and passed through by Pepco (which is substantially offset in Operating revenues).

Table of Contents

Gain on Sales of Assets
The decrease in Gain on sales of assets during the nine months ended September 30, 2018, compared to the same period in 2017, is primarily due to the sale of land in June 2017.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2018 compared to the same periods in 2017 increased due to higher outstanding debt.
Other, Net
Other, net for the three and nine months ended September 30, 2018 compared to the same periods in 2017 remained relatively consistent.
Effective Income Tax Rate
Pepco's effective income tax rate was (2.3)% and 30.4% for the three months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA.
Pepco's effective income tax rate was 3.9% and 23.3% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA, partially offset by a nonrecurring adjustment to income tax reserve balances in 2017.
See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

Table of Contents

Pepco Electric Operating Statistics and Detail
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		   Weather - Normal % Change Nine Months Ended
September 30,		   Weather - Normal % Change
2018 2017 % Change  2018 2017 % Change 
Retail Deliveries(a)
               
Residential2,446
 2,281
 7.2 % 1.4 % 6,528
 6,038
 8.1 % 0.1 %
Small commercial & industrial327
 347
 (5.8)% (8.1)% 982
 999
 (1.7)% (4.8)%
Large commercial & industrial4,298

4,146
 3.7 % 1.3 % 11,661
 11,306
 3.1 % 1.0 %
Public authorities & electric railroads181
 180
 0.6 % — % 531
 542
 (2.0)% (2.6)%
Total retail deliveries7,252
 6,954
 4.3 % 0.8 % 19,702
 18,885
 4.3 % 0.3 %
 As of September 30,
Number of Electric Customers2018 2017
Residential802,607
 790,032
Small commercial & industrial53,700
 53,543
Large commercial & industrial21,927
 21,733
Public authorities & electric railroads147
 143
Total878,381
 865,451
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

Table of Contents

Results of Operations - DPL
 Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2018 2017  2018 2017 
Operating revenues$328
 $327
 $1
 $1,001
 $971
 $30
Purchased power and fuel expense133
 129
 (4) 425
 399
 (26)
Revenues net of purchased power and fuel expense(a)
195
 198
 (3) 576
 572
 4
Other operating expenses

 

   

 

  
Operating and maintenance82
 79
 (3) 256
 227
 (29)
Depreciation and amortization47
 45
 (2) 135
 124
 (11)
Taxes other than income15
 15
 —
 43
 43
 —
Total other operating expenses144
 139
 (5) 434
 394
 (40)
Operating income51
 59
 (8) 142
 178
 (36)
Other income and (deductions)

 

 

 

 

 

Interest expense, net(15) (13) (2) (42) (38) (4)
Other, net2
 4
 (2) 7
 10
 (3)
Total other income and (deductions)(13) (9) (4) (35) (28) (7)
Income before income taxes38

50
 (12) 107

150
 (43)
Income taxes5
 19
 14
 17
 43
 26
Net income$33
 $31
 $2
 $90
 $107
 $(17)
_________
(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 natural 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.
Net Income
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017. DPL's Net income for the three months ended September 30, 2018, remained relatively consistent with the same period in 2017. The TCJA did not significantly impact DPL's Net income for the three months ended September 30, 2018 as the favorable tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017. DPL's Net income for the nine months ended September 30, 2018, was lower than the same period in 2017 primarily due to higher Operating and maintenance expense attributable to higher labor and contracting expense, deferral of accumulated merger integration costs as regulatory assets in 2017 and higher regulatory asset amortization due to additional regulatory assets related to rate case activity, partially offset by higher electric distribution base rates and higher gas distribution interim base rates charged to customers in Delaware that were put into effect in March 2018 and favorable weather and volumes. The TCJA did not significantly impact DPL's Net income for the nine months ended September 30, 2018 as the favorable tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.

Table of Contents

Revenues Net of Purchased Power and Fuel Expense
Operating revenues include revenue from the distribution and supply of electricity and natural gas 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. 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 revenue 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.
Electric and natural 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 natural 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 three and nine months ended September 30, 2018 and 2017, consisted of the following:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric50% 51% 50% 52%
Natural Gas53% 53% 33% 35%
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2018 and 2017 consisted of the following:
 September 30, 2018 September 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric72,622
 13.8% 78,426
 15.0%
Natural Gas154
 0.1% 155
 0.1%
Retail deliveries purchased from competitive electric generation suppliers represented 52% and 52% of DPL’s retail kWh sales to Delaware customers and 46% and 45% of DPL's retail kWh sales to Maryland customers for the three and nine months ended September 30, 2018, respectively and 53% and 54% of DPL's retail kWh sales to Delaware customers and 48% and 48% of DPL's retail kWh sales to Maryland customers for the three and nine months ended September 30, 2017, respectively.

Table of Contents

The changes in DPL’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
 Electric Gas Total Electric Gas Total
Weather$4
 $(1) $3
 $10
 $4
 $14
Volume1
 2
 3
 4
 3
 7
Distribution revenue(8) 1
 (7) (18) (1) (19)
Regulatory required programs(3) (2) (5) (3) (1) (4)
Transmission revenue5
 —
 5
 5
 —
 5
Other(2) —
 (2) 1
 —
 1
Total increase$(3) $—
 $(3) $(1) $5
 $4
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.
Weather. The demand for electricity and natural 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 natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2018 compared to the same period in 2017, Operating revenue net of purchased power and fuel expense related to weather was higher due to the impact of favorable weather conditions in DPL's Delaware service territory.

Table of Contents

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 natural gas service territory. The changes in heating and cooling degree-days in DPL’s service territory for the three and nine months ended September 30, 2018 compared to the same period in 2017 and normal weather consisted of the following:
Electric Service Territory    % Change
Three Months Ended September 30,2018 2017 Normal 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days7
 24
 31
 (70.8)% (77.4)%
Cooling Degree-Days1,052
 867
 863
 21.3 % 21.9 %
          
Nine Months Ended September 30,         
Heating Degree-Days2,882
 2,476
 2,906
 16.4 % (0.8)%
Cooling Degree-Days1,425
 1,228
 1,199
 16.0 % 18.8 %
Natural Gas Service Territory    % Change
Three Months Ended September 30,2018 2017 Normal 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days11
 28
 42
 (60.7)% (73.8)%
          
Nine Months Ended September 30,         
Heating Degree-Days2,995
 2,571
 3,042
 16.5 % (1.5)%
Volume. The increase in Operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2018 compared to the same period in 2017, primarily reflects the impact of increased average residential customer usage and growth.
Distribution Revenue.  The decrease in electric distribution revenue for the three months ended September 30, 2018, and electric and gas distribution revenue for the nine months ended September 30, 2018 compared to the same periods in 2017 was primarily due to reduced electric distribution rates and gas interim distribution rates in Delaware that were put into effect in March 2018 which reflect the impact of the lower federal income tax rate.  The increase in gas distribution revenue for the three months ended September 30, 2018 compared to the same period in 2017 is primarily due to customer sales mix. See Note 6 — 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 Taxes other than income in DPL's Consolidated Statements of Operations and Comprehensive Income. See Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs. Revenue from regulatory required programs decreased for the three and nine months ended September 30, 2018 compared to the same periods in 2017 primarily due to decreases of surcharge rates.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, the highest daily peak load and other billing adjustments. The increase in transmission revenue for the three

Table of Contents

and nine months ended September 30, 2018 compared to the same period in 2017 is a result of a higher rates effective June 2018.
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, and recoveries of other taxes.
Operating and Maintenance Expense
 Three Months Ended
September 30,		 Increase (Decrease) Nine Months Ended
September 30,		 Increase (Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense - baseline$78
 $74
 $4
 $244
 $215
 $29
Operating and maintenance expense - regulatory required programs(a)
4
 5
 (1) 12
 12
 —
Total operating and maintenance expense$82
 $79
 $3
 $256
 $227
 $29
_________
(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 the three and nine months ended September 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor and contracting(a)
$2
 $11
Uncollectible accounts expense2
 4
Merger costs(b)
(2) 7
Other2
 7
 4
 29
    
Regulatory required programs(1) —
Total increase$3
 $29
_________
(a)Includes additional costs associated with mutual assistance programs. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
(b)Primarily due to a deferral of accumulated merger integration costs as regulatory assets in 2017.

Table of Contents


Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018
 Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$2
 $5
Regulatory asset amortization(b)
3
 10
Regulatory required programs(c)


(3) (4)
Total increase$2
 $11
_________
(a)Depreciation expense increased due to ongoing capital expenditures.
(b)Regulatory asset amortization increased due to additional regulatory assets related to rate case activity.
(c)Depreciation and amortization expenses for regulatory required programs 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.
Taxes Other Than Income
Taxes other than income for the three and nine months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 2018 compared to the same period in 2017 increased due to higher outstanding debt.
Other, Net
Other, net for the three and nine months ended September 30, 2018 compared to the same period in 2017 remained relatively consistent.
Effective Income Tax Rate
DPL's effective income tax rate was 13.2% and 38.0% for the three months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA.
DPL's effective income tax rate was 15.9% and 28.7% for the nine months ended September 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA, partially offset by a nonrecurring adjustment to income tax reserve balances in 2017.
See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

DPL Electric Operating Statistics and Detail
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		 % Change Weather - Normal % Change Nine Months Ended
September 30,		 % Change Weather - Normal % Change
2018 2017   2018 2017  
Retail Deliveries(a)
               
Residential1,537
 1,439
 6.8% — % 4,203
 3,843
 9.4 % 1.7 %
Small commercial & industrial651
 636
 2.4% (0.1)% 1,756
 1,693
 3.7 % 1.5 %
Large commercial & industrial1,282
 1,245
 3.0% 0.2 % 3,548
 3,440
 3.1 % 1.3 %
Public authorities & electric railroads11
 10
 10.0% 8.9 % 33
 35
 (5.7)% (5.3)%
Total retail deliveries3,481
 3,330
 4.5% 0.1 % 9,540
 9,011
 5.9 % 1.5 %
 As of September 30,
Number of Electric Customers2018 2017
Residential463,017
 458,790
Small commercial & industrial61,277
 60,542
Large commercial & industrial1,400
 1,406
Public authorities & electric railroads622
 633
Total526,316
 521,371
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
DPL Natural Gas Operating Statistics and Detail
Retail Deliveries to Customers (in mmcf)Three Months Ended
September 30,		 % Change Weather - Normal % Change Nine Months Ended
September 30,		 % Change Weather - Normal % Change
2018 2017   2018 2017  
Retail Deliveries(a)
               
Residential360
 331
 8.8% 16.6% 5,801
 4,785
 21.2% 4.8 %
Small commercial & industrial309
 290
 6.6% 11.3% 2,831
 2,486
 13.9% (1.0)%
Large commercial & industrial454
 448
 1.3% 1.3% 1,438
 1,408
 2.1% 2.2 %
Transportation1,260
 1,197
 5.3% 5.6% 4,893
 4,690
 4.3% 1.8 %
Total natural gas deliveries2,383
 2,266
 5.2% 7.2% 14,963
 13,369
 11.9% 2.4 %

Table of Contents

 As of September 30,
Number of Gas Customers2018 2017
Residential123,145
 121,238
Small commercial & industrial9,798
 9,683
Large commercial & industrial19
 17
Transportation154
 155
Total133,116
 131,093
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

Table of Contents

Results of Operations - ACE
 Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
 2018 2017  2018 2017 
Operating revenues$406
 $370
 $36
 $981
 $915
 $66
Purchased power expense198
 176
 (22) 486
 442
 (44)
Revenues net of purchased power expense(a)
208
 194
 14
 495
 473
 22
Other operating expenses    
     
Operating and maintenance85
 72
 (13) 250
 225
 (25)
Depreciation and amortization38
 41
 3
 107
 113
 6
Taxes other than income1
 2
 1
 4
 6
 2
Total other operating expenses124
 115
 (9) 361
 344
 (17)
Operating income84
 79
 5
 134
 129
 5
Other income and (deductions)    
     
Interest expense, net(16) (15) (1) (48) (46) (2)
Other, net1
 1
 —
 2
 6
 (4)
Total other income and (deductions)(15)
(14) (1) (46)
(40) (6)
Income before income taxes69

65
 4
 88

89
 (1)
Income taxes8
 24
 16
 12
 12
 —
Net income$61
 $41
 $20
 $76
 $77
 $(1)
_________
(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 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
Three Months Ended September 30, 2018 Compared to Three Months Ended September 30, 2017.ACE's Net income for the three months ended September 30, 2018, was higher than the same period in 2017, primarily due to higher electric distribution base rates charged to customers in New Jersey that became effective in October 2017, as well as favorable weather and volume. The TCJA did not significantly impact ACE’s Net income for the three months ended September 30, 2018 as the favorable income tax impacts were predominately offset by lower revenues resulting from the pass back of the tax savings through customer rates. 
Nine Months Ended September 30, 2018 Compared to Nine Months Ended September 30, 2017.ACE's Net income for the nine months ended September 30, 2018, remained relatively consistent with the same period in 2017. The TCJA did not significantly impact ACE’s Net income for the nine months ended September 30, 2018 as the favorable income tax impacts were predominately offset by lower revenues resulting from the pass back of the tax savings through customer rates. 

Table of Contents

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. 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 wholesale markets for 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.
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.

248
Table of Contents


Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30, 2017,2018 compared to the same periodsperiod in 2016,2017 consisted of the following:
 Three Months Ended  
 September 30,		 Nine Months Ended 
 September 30,
 2017 2016 2017 2016
Electric44% 44% 48% 46%
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Electric43% 44% 46% 48%
Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 20172018 and 20162017 consisted of the following:
 September 30, 2017 September 30, 2016
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric91,219
 17% 96,837
 18%
Operating revenues 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 wholesale markets for 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.
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.
 September 30, 2018 September 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric82,556
 15% 91,219
 17%
The changes in ACE’s operating revenue net of purchased power expense for the three and nine months ended September 30, 20172018 compared to the same periodsperiod in 20162017 consisted of the following:
Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017		Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Weather$(5) $(7)$8
 $12
Volume(12) (15)7
 13
Pricing - distribution revenues16
 36
Distribution revenue6
 12
Regulatory required programs(9) (19)(4) (14)
Transmission revenues4
 17
Transmission revenue(4) (3)
Other—
 (1)1
 2
Total (decrease) increase$(6) $11
Total increase$14
 $22

Table of Contents

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 three and nine months ended September 30, 20172018 compared to the same periodsperiod in 2016,2017, operating revenue net of purchased power and fuel expense related to weather was lowerhigher due to the impact of unfavorablefavorable weather conditions in ACE's service territory.
For retail customers of ACE, distribution revenues are not decoupled from 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.

249
Table of Contents


Heating and cooling degree daysdegree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree daysdegree-days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree daysdegree-days in ACE’s service territory for the three and nine months ended September 30, 20172018 compared to the same periodsperiod in 20162017 consisted of the following:
  Normal % Change
2017 2016 2017 vs. 2016 2017 vs. Normal
Heating and Cooling Degree-Days  Normal % Change
Three Months Ended September 30,         2018 2017 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days23
 17
 42
 35.3 % (45.2)%1
 23
 39
 (95.7)% (97.4)%
Cooling Degree-Days830
 1,006
 806
 (17.5)% 3.0 %1,093
 830
 817
 31.7 % 33.8 %
      

 

      

 

Nine Months Ended September 30,      

 

      

 

Heating Degree-Days2,608
 2,938
 3,103
 (11.2)% (16.0)%2,928
 2,608
 3,068
 12.3 % (4.6)%
Cooling Degree-Days1,153
 1,267
 1,092
 (9.0)% 5.6 %1,447
 1,153
 1,110
 25.5 % 30.4 %
Volume.During the three and nine months ended September 30, 2017,2018 compared to the same period in 2016,2017 the decreaseincrease in operating revenue net of purchased power expense related to delivery volume, exclusive of the effects of weather, is primarily due to lowerhigher average customerresidential and commercial usage. During the nine months ended September 30, 2017 compared to the same period in 2016, primarily reflects lower average customer usage, partially offset by the impact of customer growth.
Pricing—Distribution Revenues. Revenue.The increase in operatingdistribution revenue net of purchased power expense for the three and nine months ended September 30, 2017,2018 compared to the same periodsperiod in 2016,2017 was primarily due to the impact of higher electric distribution base rates charged to customers that became effective in August 2016.November 2017, partially offset by the impact of reduced distribution rates to reflect the lower federal income tax rate. See Note 56 — 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 Taxes other than income in ACE's Consolidated Statements of Operations and Comprehensive Income. Refer to theSee Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs. Revenue from regulatory required programs decreased for the three and nine months ended September 30, 2018 compared to the same periods in 2017 due to a rate decrease effective October 2017 for the ACE Transition Bonds.

Table of Contents

Transmission Revenues. Revenue.Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, the highest daily peak load and other billing adjustments. The increasedecrease in transmission revenue net of purchased power expense for the three months ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 and related to increases in transmission plant investment and operating expenses. The increase in revenue net of purchased power expense for the nine months ended September 30, 20172018 compared to the same periods in 2017 was primarily due to the impact of the lower federal income tax rate.
Other.Other revenue, which can vary period in 2016 is a result of higher rates effective June 1, 2017 and June 1, 2016to period, includes rental revenue, revenue related to increases in transmission plant investmentlate payment charges, assistance provided to other utilities through mutual assistance programs, and operating expenses.recoveries of other taxes.
Operating and Maintenance Expense
Three Months Ended September 30, Increase (Decrease) Nine Months Ended September 30, 
Increase
(Decrease)
Three Months Ended September 30, Increase (Decrease) Nine Months Ended September 30, 
Increase
(Decrease)
2017 2016 2017 2016 2018 2017 2018 2017 
Operating and maintenance expense - baseline$71
 $66
 $5
 $222
 $343
 $(121)$69
 $62
 $7
 $227
 $199
 $28
Operating and maintenance expense - regulatory required programs(a)
1
 1
 —
 3
 3
 —
16
 10
 6
 23
 26
 (3)
Total operating and maintenance expense$72
 $67
 $5
 $225
 $346
 $(121)$85
 $72
 $13
 $250
 $225
 $25
_________
(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.

250
Table of Contents


The changes in Operating and maintenance expense for the three and nine months ended September 30, 20172018 compared to the same periodsperiod in 20162017 consisted of the following:
 Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor, other benefits, contracting and materials$3
 $6
Storm-related costs(3) (2)
BSC and PHISCO allocations(a)
—
 (11)
Deferral of merger-related costs to regulatory asset(9) (9)
Merger commitments(b)
10
 (111)
Other4
 6
Total increase (decrease)$5
 $(121)
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor and contracting(a)
$7
 $18
Merger costs(b)
8
 7
Other(8) 3
 7
 28
    
Regulatory required programs6
 (3)
Total increase$13
 $25
_________
(a)Primarily related to merger severanceIncludes additional costs associated with mutual assistance programs. An equal and compensation costsoffsetting increase has been recognized in 2016.Operating revenues for the period presented.
(b)Primarily relateddue to merger-related commitments for customer rate credits and charitable contributions recognizeda deferral of accumulated merger integration costs as regulatory assets in 2016.2017.

Table of Contents

Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and nine months ended September 30, 20172018 compared to the same periodsperiod in 20162017 consisted of the following:
Three Months Ended 
 September 30, 2017		 Nine Months Ended 
 September 30, 2017		Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$1
 $4
$1
 $4
Regulatory asset amortization—
 (2)2
 5
Regulatory required programs(b)
(9) (19)(6) (15)
Total decrease$(8) $(17)$(3) $(6)
_________
(a)Depreciation expense increased due to ongoing capital expenditures.
(b)Regulatory required programs decreased for the three and nine months ended September 30, 2017 compared to the same periods in 2016 as a result of lower revenue due to rate decreases effective October 20162017 for the ACE Transition Bond Charge and Market Transition Charge Tax.Bonds. Depreciation and amortization expenses for regulatory required programs 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 and Operating and maintenance expense.revenues.
Taxes Other Than Income
Taxes other than income for the three and nine months ended September 30, 20172018 compared to the same periodsperiod in 2016,2017 remained relatively constant.
Gain on sales of assets
Gain on sales of assets for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.consistent.
Interest Expense, Net
Interest expense, net for the three and nine months ended September 30, 20172018 compared to the same periodsperiod in 20162017 remained relatively constant.consistent.
Other, Net
Other, net for the three andmonths ended September 30, 2018 compared to the same period in 2017 remained relatively consistent. The decrease in Other, net for the nine months ended September 30, 20172018 compared to the same periodsperiod in 2016, remained relatively constant.

251
Table of Contents


2017 was primarily due to lower income from AFUDC equity.
Effective Income Tax Rate
ACE's effective income tax rate was 36.9%11.6% and 32.9%36.9% for the three months ended September 30, 2018 and 2017, and 2016, respectively. The decrease in the effective income tax rate for the three months ended September 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA.
ACE's effective income tax rate was 13.5%13.6% and 13.8%13.5% for the nine months ended September 30, 2018 and 2017, and 2016, respectively. InThe increase in the first quartereffective income tax rate for the nine months ended September 30, 2018 compared to the same period in 2017 is primarily due to the absence of 2017, ACE decreased its liability foran unrecognized tax benefitsbenefit from 2017, partially offset by $22 million resultinga nonrecurring adjustment to income tax reserve balances in a benefit to Income taxes and a corresponding decrease in its effective tax rate. 2017.
See Note 12 -— Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Table of Contents

ACE Electric Operating Statistics and Revenue Detail
Three Months Ended  
 September 30,		 % Change Weather - Normal % Change Nine Months Ended 
 September 30,		 % Change Weather - Normal % Change
Retail Deliveries to Customers (in GWhs)Three Months Ended
September 30,		 % Change Weather - Normal % Change Nine Months Ended
September 30,		 % Change Weather - Normal % Change
2017 2016 % Change Weather - Normal % Change 2017 2016 % Change Weather - Normal % Change2018 2017 2018 2017 
Retail Deliveries(a)
                       
Residential1,349
 1,575
 (14.3)% (10.4)% 3,042
 3,327
 (8.6)% (6.0)%1,548
 1,349
 14.8% 6.2% 3,363
 3,042
 10.6% 4.3%
Small commercial & industrial407
 426
 (4.5)% (1.9)% 992
 998
 (0.6)% 0.8 %442
 407
 8.6% 4.0% 1,066
 992
 7.5% 4.3%
Large commercial & industrial939
 1,032
 (9.0)% (6.3)% 2,557
 2,705
 (5.5)% (4.6)%1,030
 939
 9.7% 6.7% 2,725
 2,557
 6.6% 5.0%
Public authorities & electric railroads9
 11
 (18.2)% (18.2)% 33
 35
 (5.7)% (5.7)%10
 9
 11.1% 8.2% 36
 33
 9.1% 8.2%
Total retail deliveries2,704
 3,044
 (11.2)% (7.8)% 6,624
 7,065
 (6.2)% (4.5)%3,030
 2,704
 12.1% 6.0% 7,190
 6,624
 8.5% 4.6%
 As of September 30,
Number of Electric Customers2017 2016
Residential486,212
 483,542
Small commercial & industrial60,982
 60,875
Large commercial & industrial3,726
 3,796
Public authorities & electric railroads633
 593
Total551,553
 548,806
 Three Months Ended  
 September 30,		 % Change Nine Months Ended 
 September 30,		 % Change
Electric Revenue2017 2016  2017 2016 
Retail Sales(a)
           
Residential$211
 $249
 (15.3)% $484
 $530
 (8.7)%
Small commercial & industrial53
 55
 (3.6)% 129
 133
 (3.0)%
Large commercial & industrial49
 57
 (14.0)% 143
 158
 (9.5)%
Public authorities & electric railroads3
 4
 (25.0)% 10
 10
 — %
Total retail316
 365
 (13.4)% 766
 831
 (7.8)%
Other revenue(b)
54
 56
 (3.6)% 149
 151
 (1.3)%
Total electric revenue(c)
$370
 $421
 (12.1)% $915
 $982
 (6.8)%
 As of September 30,
Number of Electric Customers2018 2017
Residential489,961
 486,212
Small commercial & industrial61,141
 60,982
Large commercial & industrial3,569
 3,726
Public authorities & electric railroads656
 633
Total555,327
 551,553
_________
(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 $0 million and $1 million for the three months ended September 30, 2017 and 2016, respectively, and $2 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.

252
Table of Contents


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 September 30, 2017. 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 nine months ended September 30, 2017 and 2016. All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to unsecured revolving credit facilities with aggregate bank commitments of $9 billion. In addition, Generation has $525$545 millionin bilateral facilities with banks which have various expirations between December 2017January 2019 and January 2019.March 2020. 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.additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd, PECO, BGE, Pepco, DPL and ACE operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further discussionadditional information of the Registrants’ debt and credit agreements.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 13 - Nuclear Decommissioning— Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information on the NRC minimum funding requirements.
If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value. A shortfall could require Exelon to postthat Generation address the shortfall by, among other things, obtaining a parental guaranteesguarantee for Generation’s share of the obligations.funding assurance. However, the amount of any required guarantees or other assurance 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. As discussed in Note 13 — Nuclear DecommissioningAsset Retirement Obligations of the Combined Notes to Consolidated Financial Statements, Generation filed its biennialannual decommissioning funding status report with the NRC on March 31, 201728, 2018 for shutdown reactors and demonstrated adequate funding assurance for all nuclear units currently operating.reactors within five years of shut down. As of September 30, 2017,2018, across the four alternative

Table of Contents

decommissioning approaches available, Exelon would not be required to post a parental guarantee for TMI or Oyster Creek. In the event PSEG decides to early retire Salem, Generation estimates a parental guarantee of up to $115$55 million from Exelon could be required for TMI,Salem, dependent upon the ultimate decommissioning approach selected. TMI passes the NRC minimum funding test based on the unit's 2019 retirement date under the decommissioning approach currently considered to be the most likely. For Oyster Creek, none of the alternative decommissioning approaches available would require Exelon to post a parental guarantee.
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.

253
Table of Contents


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 EnergyDOE reimbursement agreements or future litigation, across the four alternative decommissioning approaches available, if TMI or Oyster Creek were to fail to obtain the exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $190$200 million and $150$215 million net of taxes, respectively, dependent upon the ultimate decommissioning approach selected. UnderIn the decommissioning approach currently consideredevent PSEG decides to early retire Salem and Salem were to fail to obtain the most likely for each unit,exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $170 million and $130$95 million net of taxes, respectively, if TMI ortaxes.
On July 31, 2018, Generation entered into an agreement for the sale of Oyster Creek werewhich is expected to fail to obtain the exemption.
Junior Subordinated Notes
In June 2014, Exelon issued $1.15 billion of junior subordinated notesoccur in the formsecond half of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract.   As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”).  Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of September 30, 2017.2019. See Note 174 - Earnings Per ShareMergers, Acquisitions and Equity of the Combined Notes to Consolidated Financial StatementsDispositions for furtheradditional information on the issuancesale of common stock.Oyster Creek to Holtec.
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 2423 — Commitments and Contingenciesof the Combined Notes to Consolidated Financial Statements of the Exelon 20162017 Form 10-K for further discussionadditional information of regulatory and legal proceedings and proposed legislation.

254
Table of Contents


The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the nine months ended September 30, 20172018 and 2016:2017:
 Nine Months Ended 
 September 30,		  
 2017 
2016(c)
 Variance
Net income$1,911
 $956
 $955
Add (subtract):     
Non-cash operating activities(a)
5,011
 5,946
 (935)
Pension and non-pension postretirement benefit contributions(344) (283) (61)
Income taxes167
 527
 (360)
Changes in working capital and other noncurrent assets and liabilities(b)
(1,003) (516) (487)
Option premiums received (paid), net35
 (24) 59
Collateral (posted) received, net(100) 757
 (857)
Net cash flows provided by operations$5,677
 $7,363
 $(1,686)
 Nine Months Ended
September 30,		  
 2018 2017 Variance
Net income$1,979
 $1,928
 $51
Add (subtract):     
Non-cash operating activities(a)
5,452
 5,016
 436
Pension and non-pension postretirement benefit contributions(362) (344) (18)
Income taxes166
 167
 (1)
Changes in working capital and other noncurrent assets and liabilities(b)
(746) (1,029) 283
Option premiums received (paid), net(36) 35
 (71)
Collateral (posted) received, net222
 (100) 322
Net cash flows provided by operations$6,675
 $5,673
 $1,002
_________
(a)Represents when applicable, depreciation, amortization and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts, pension and other postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets, PHI merger commitmentgain on sale of assets and severance charges,businesses and other non-cash charges. See Note 19 -18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for further detailadditional information on non-cash operating activity.
(b)Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.
(c)Includes PHI Consolidated activity from March 24, 2016 to September 30, 2016.
Pension and Other Postretirement Benefits
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). Exelon's funding strategy for its qualified pension plans is to contribute the greater of (1) $300 million (inclusive of PHI) and (2) 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. Unlike the qualified pension plans, Exelon's non-qualified pension plans are not funded given that they are not subject to statutory minimum contribution requirements.
While other postretirement plans are plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon's management has historically considered several factors in determining the level of contributions to its other postretirement benefit plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery).
To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.

Table of Contents

On October 3, 2017, the USU.S. Department of Treasury and IRS released final regulations updating the mortality tables to be used for defined benefit pension plan funding, as well as the valuation of lump sum and other accelerated distribution options, effective for plan years beginning in 2018. The new mortality tables reflect improved projected life expectancy as compared to the existing table, which is generally expected to increase minimum pension funding requirements, Pension Benefit Guaranty Corporation premiums and the value of lump sum distributions. The IRS will permitpermits plan sponsors the option of using existingdelaying use of the new mortality tables for determining minimum funding requirements for 2018.until 2019, which Exelon has utilized. The one-year delay does not apply for use of the mortality tables to determine the present value of lump sum distributions. Exelon is still evaluating any potential impacts of the new mortality tables.
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).
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.
Tax Matters
The Registrants’ future cash flows from operating activities may be affected by the following tax matters:
Exelon appealedPursuant to the Tax Court’s like-kind exchange decisionTCJA, beginning in 2018 Generation is expected to have higher operating cash flows in the third quarter of 2017 and expects that a paymentrange of approximately $1.3$1.2 billion relatedto $1.6 billion for the period from 2018 to 2021, reflecting the reduction in the corporate federal income tax rate and full expensing of capital investments.
The TCJA is generally expected to result in lower operating cash flows for the Utility Registrants as a result of the elimination of bonus depreciation and lower customer rates. Increased operating cash flows for the Utility Registrants from lower corporate federal income tax rates is expected to be more than offset over time by lower customer rates resulting from lower income tax expense recoveries and the settlement of deferred income tax net regulatory liabilities established pursuant to the like-kind exchangeTCJA, partially offset by the impacts of higher rate base. The amount and timing of settlement of the net regulatory liabilities will be due, including $300 million attributabledetermined by the Utility Registrants’ respective rate regulators, subject to ComEd,certain IRS “normalization” rules. The table below sets forth the Registrants’ estimated categorization of their net regulatory liabilities as of December 31, 2017. The amounts in the fourth quarter of 2017. While Exelon will receive atable below are shown on an after-tax basis reflecting future net cash outflows after taking into consideration the income tax benefit of approximately $350 millionbenefits associated with the deductionultimate settlement with customers.
 Exelon ComEd 
PECO(a)
 BGE PHI PEPCO DPL ACE
Subject to IRS Normalization Rules$3,040 $1,400 $533 $459 $648 $299 $195 $153
Subject to Rate Regulator Determination1,694 573 43 324 754 391 194 170
Net Regulatory Liabilities$4,734 $1,973 $576 $783 $1,402 $690 $389 $323
__________
(a)Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants. See Note 6 - Regulatory Matters for additional information.
Net regulatory liability amounts subject to normalization rules generally may not be passed back to customers any faster than over the interest, Exelon currently has a net operating loss carryforwardremaining useful lives of the underlying assets giving rise to the associated deferred income taxes. Such deferred income taxes generally relate to property, plant and thus does notequipment with remaining useful lives ranging from 30 to 40 years across the Utility Registrants. For the remaining amounts, the pass back period is subject to determinations by the rate regulators.
The Utility Registrants expect to realize thefund any such required incremental operating cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange isoutflows using a combination of third party debt financings and equity funding from Exelon in combinations generally consistent with existing capitalization ratio structures. To fund any

255
Table of Contents


approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts on ComEd’sadditional equity from the like-kind exchange position.
Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. In the third quarter of 2017, the $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuantcontributions to the hold harmless agreement, was settled with Exelon. Any remaining amounts dueUtility Registrants, Exelon would have available to it its typical sources, including, but not limited to, the IRS will be paid by Exelon inincreased operating cash flows at Generation referenced above, which over time are expected to exceed the fourth quarterincremental equity needs at the Utility Registrants.
The Utility Registrants have worked with their state regulatory commissions to determine the amount and timing of 2017. Exelon funded the $1.25 billion deposit with a combinationpassing back of cashTCJA income tax savings benefits to customers. See Note 6 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on hand and short-term borrowings. their filings.
See Note 12 - Income Taxes for further discussion of the like-kind exchange tax position.Combined Notes to Consolidated Financial Information for additional information on the amounts of the net regulatory liabilities subject to determinations by rate regulators.
At this time, many of the states in which Exelon does business have issued guidance regarding TCJA and the impact is not material.
State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax, property taxes and other taxes or the imposition, extension or permanence of temporary tax increases. On July 6, 2017, Illinois enacted Senate Bill 9, which permanently increased Illinois’ total corporate income tax rate from 7.75% to 9.50% effective July 1, 2017. The rate increase is not expected to have a material ongoing impact to Exelon’s, Generation’s or ComEd’s future cash taxes. See Note 12 - Income Taxes for further discussion of the Illinois tax rate change.
Cash flows from operations for the nine months ended September 30, 20172018 and 20162017 by Registrant were as follows:
Nine Months Ended 
 September 30,		Nine Months Ended
September 30,
2017 20162018 2017
Exelon$5,677
 $7,363
$6,675
 $5,673
Generation2,270
 3,723
3,411
 2,270
ComEd1,120
 1,749
1,118
 1,120
PECO603
 582
492
 603
BGE704
 660
675
 701
PHI845
 795
Pepco348
 504
396
 348
DPL292
 267
292
 292
ACE158
 315
160
 158
 Successor  Predecessor
 Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016
 January 1, 2016 to March 23, 2016
PHI$797
 $546
  $264
Changes in the Registrants'cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for the Registrants for the nine months ended September 30, 20172018 and 20162017 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 the nine months ended September 30, 20172018 and 2016,2017, Generation had net collections/(payments)/collections of counterparty cash collateral of $(77)$228 million and $759$(77) million, respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.

Table of Contents

During the nine months ended September 30, 20172018 and 2016,2017, Generation had net (payments)/collections of approximately $(35)$(36) million and $24$35 million, respectively, related to purchases and sales of options. The level of option activity in a given period may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.

256
Table of Contents


ComEd
During nine months ended September 30, 2017 and 2016, ComEd posted approximately $24 million and $2 million of cash collateral with PJM, respectively.  ComEd’s collateral posted with PJM has increased year over year primarily due to an increase in ComEd’s RPM credit requirements and peak market activity with PJM. As of September 30, 2017 and 2016, ComEd had approximately $47 million and $33 million cash collateral posted with PJM, respectively.
For further discussion regarding changes in non-cash operating activities, please refer toSee Note 19 -18 — Supplemental Financial Information of the Combined Notes to theConsolidated Financial Statements.Statements for additional information regarding changes in non-cash operating activities.
Cash Flows from Investing Activities
Cash flows used in investing activities for the nine months ended September 30, 20172018 and 20162017 by Registrant were as follows: 
 Nine Months Ended 
 September 30,
 2017
2016
Exelon$(5,810) $(13,219)
Generation(1,903) (3,278)
ComEd(1,731) (1,919)
PECO(457) (438)
BGE(586) (614)
Pepco(439) (435)
DPL(293) (254)
ACE(241) (227)

Successor  Predecessor

Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016 
January 1, 2016 to March 23, 2016
PHI$(991)
$(631)  $(343)
 Nine Months Ended
September 30,
 2018
2017
Exelon$(5,609) $(5,743)
Generation(1,806) (1,875)
ComEd(1,518) (1,681)
PECO(609) (457)
BGE(659) (609)
PHI(986) (990)
Pepco(472) (438)
DPL(253) (293)
ACE(248) (242)
Significant investing cash flow impacts for the Registrants for nine months ended September 30, 20172018 and 20162017 were as follows:
Exelon
During the nine months ended September 30, 2017,2018, Exelon had expendituresproceeds of $23 million and $178$85 million relating to the acquisitionssale of ConEdison Solutionsits interest in an electrical contracting business that primarily installs, maintains and the FitzPatrick facility, respectively. During the nine months ended September 30, 2016, Exelon had expenditures of $6.6 billion relating to the acquisition of PHI.repairs underground and high-voltage cable transmission and distribution services.
During the nine months ended September 30, 2016,2018, Exelon had proceedsexpenditures of $360$57 million as a resultrelating to the acquisition of early termination of direct financing leases.
Generationthe Handley Generating Station.
During the nine months ended September 30, 2017, Exelon had expenditures of $23 million and $178 million relating to the acquisitions of ConEdison Solutions and the FitzPatrick facility, respectively.
During the nine months ended September 30, 2017, Exelon had proceeds of $218 million from sales of long-lived assets.
Capital Expenditure Spending
Generation

Table of Contents

Generation has entered into several agreements to acquire equity interests in privately held and development stage entities which develop energy-related technologies.  The agreements contain a series of scheduled investment commitments, including in-kind service contributions. There are anticipated expenditures remaining through 2019 to

257
Table of Contents


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 of the Exelon 2016 Form 10-K for further details of Generation’s equity interests.
Capital expenditures by Registrant for the nine months ended September 30, 20172018 and 20162017 and projected amounts for the full year 20172018 are as follows:
 
Projected
Full Year
2017(a)
 Nine Months Ended 
 September 30,
 2017 2016
Exelon(b)
$8,075
 $5,556
 $6,368
Generation2,450
 1,654
 2,651
ComEd(c)
2,200
 1,698
 1,950
PECO775
 537
 448
BGE925
 615
 611
Pepco625
 439
 392
DPL425
 294
 260
ACE300
 242
 227
 
Projected
Full Year
2017 (a)
 Successor  Predecessor
  Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016  January 1, 2016 to March 23, 2016
PHI(d)
$1,375
 $995
 $624
  $273
 
Projected
Full Year
2018(a)
 Nine Months Ended
September 30,
 2018 2017
Exelon$7,850
(b) 
$5,497
 $5,556
Generation2,325
 1,660
 1,654
ComEd(c)
2,125
 1,540
 1,698
PECO850
 615
 537
BGE1,000
 667
 615
PHI1,500
(d) 
988
 995
Pepco700
 475
 439
DPL400
 254
 294
ACE400
 247
 242
_________
(a)Total projected capital expenditures do not include adjustments for non-cash activity. Amounts are rounded to the nearest $25 million.
(b)Includes corporate operations, BSC, and PHISCO rounded to the nearest $25 million.PHISCO.
(c)The 2017capital expenditures and 2018 projections include approximately $274$81 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over a ten yearten-year period, through 2022,2021, to modernize and storm-harden its distribution system and to implement smart grid technology.
(d)Includes PHISCO rounded to the nearest $25 million.PHISCO.
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Generation
Approximately 37%40% and 21%10% of the projected 20172018 capital expenditures at Generation are for the acquisition of nuclear fuel, and growth (primarilythe construction of new natural gas plant construction and distributed generation),solar facilities, respectively, with the remaining amounts reflecting investment in renewable energy and additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that they will fund capital expenditures with internally generated funds and borrowings.
ComEd, PECO, BGE, Pepco, DPL and ACE
Approximately 93% of the projected 2017Projected 2018 capital expenditures at ComEd and 100% of the projected of the projected 2017 capital expenditures at PECO, BGE, Pepco, DPL, and ACEUtility Registrants 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 2010, NERC provided guidance to transmission owners that recommended the Utility Registrants perform

Table of Contents

assessments of their transmission lines. ComEd, PECO and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd PECO and BGEPECO will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s and PECO’s and BGE’s forecasted 20172018 capital expenditures above reflect capital spending for remediation to be completed through 2018.2019. DPL, ACE, and BGE are complete with their assessments and Pepco DPL and ACE havehas substantially completed their assessmentsits assessment and thus do not expect significant capital expenditures related to this guidance in 2017.

258
Table of Contents


2018.
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 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.parent.
Cash Flows from Financing Activities
Cash flows provided by (used in) financing activities for the nine months ended September 30, 20172018 and 20162017 by Registrant were as follows: 
 Nine Months Ended 
 September 30,
 2017 2016
Exelon$701
 $1,251
Generation(297) (501)
ComEd812
 147
PECO121
 77
BGE(112) 286
Pepco199
 28
DPL(42) (14)
ACE(13) 74
 Successor  Predecessor
 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016  January 1, 2016 to March 23, 2016
PHI$161
 $65
  $372
 Nine Months Ended
September 30,
 2018 2017
Exelon$65
 $701
Generation(820) (297)
ComEd536
 812
PECO(51) 121
BGE82
 (112)
PHI260
 161
Pepco83
 199
DPL69
 (42)
ACE94
 (13)
Debt
See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further detailsadditional information of the Registrants’ debt issuances.

Table of Contents

Dividends
Cash dividend payments and distributions during the nine months ended September 30, 20172018 and 20162017 by Registrant were as follows:
 Nine Months Ended 
 September 30,
 2017 2016
Exelon$921
 $873
Generation494
 167
ComEd316
 275
PECO216
 208
BGE(a)
148
 142
Pepco133
 92
DPL82
 39
ACE53
 24
 Successor  Predecessor
 Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016  January 1, 2016 to March 23, 2016
PHI$267
 $174
  $—
_________
(a)Includes dividends paid on BGE’s preference stock in 2016.

259
Table of Contents


 Nine Months Ended
September 30,
 2018 2017
Exelon$999
 $921
Generation688
 494
ComEd345
 316
PECO300
 216
BGE157
 148
PHI232
 267
Pepco128
 133
DPL58
 82
ACE46
 53
Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 20172018 and for the fourththird quarter of 20172018 were as follows:
Period Declaration Date Shareholder of Record Date Dividend Payable Date 
Cash per Share(a)
First Quarter 2017 January 31, 2017 February 15, 2017 March 10, 2017 $0.3275
Second Quarter 2017 April 25, 2017 May 15, 2017 June 9, 2017 $0.3275
Third Quarter 2017 July 25, 2017 August 15, 2017 September 8, 2017 $0.3275
Fourth Quarter 2017 September 25, 2017 November 15, 2017 December 8, 2017 $0.3275
Period Declaration Date Shareholder of Record Date Dividend Payable Date 
Cash per Share(a)
First Quarter 2018 January 30, 2018 February 15, 2018 March 9, 2018 $0.3450
Second Quarter 2018 May 1, 2018 May 15, 2018 June 8, 2018 $0.3450
Third Quarter 2018 July 24, 2018 August 15, 2018 September 10, 2018 $0.3450
Fourth Quarter 2018 September 24, 2018 November 15, 2018 December 10, 2018 $0.3450
_________
(a)Exelon's Board of Directors approved a revisedan updated dividend policy. The approved policy will raise the dividend 2.5%providing an increase of 5% each year for the next three years,period covering 2018 through 2020, beginning with the June 2016 dividend and subject to Board approval.March 2018 dividend.
Short-Term Borrowings
Short-term borrowings incurred (repaid) during the nine months ended September 30, 20172018 and 20162017 by Registrant were as follows:
Nine Months Ended 
 September 30,		Nine Months Ended
September 30,
2017 20162018 2017
Exelon$(559) $(1,271)$(93) $(559)
Generation(609) 43
—
 (609)
ComEd—
 (284)—
 —
PECO—
 —
BGE(45) (210)(77) (45)
PHI(16) (404)
Pepco(23) (64)38
 (23)
DPL54
 (88)(216) 54
ACE65
 (5)162
 65
 Successor  Predecessor
 Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016 
January 1, 2016 to March 23, 2016
PHI$(404) $(820)  $379

260
Table of Contents


Contributions from Parent/Member
Contributions received from Parent/Member for the nine months ended September 30, 20172018 and 20162017 by Registrant were as follows:
 Nine Months Ended 
 September 30,
 2017 2016
Generation$102
 $142
ComEd (a)(b)
567
 188
PECO (b)
16
 18
BGE (b)
77
 28
Pepco (c)
161
 187
DPL (c)
—
 113
ACE (c)
—
 139
 Successor  Predecessor
 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016  January 1, 2016 to March 23, 2016
PHI (b)
$758
 $1,088
  $—
 Nine Months Ended
September 30,
 2018 2017
Generation$54
 $102
ComEd(a)(b)
387
 567
PECO(b)
71
 16
BGE (b)
18
 77
PHI(b)
237
 758
Pepco(c)
85
 161
DPL(c)
150
 —
_________
(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 and transmission upgrades.
(b)Contribution paid by Exelon.
(c)Contribution paid by PHI.
Other
For the nine months ended September 30, 2017,2018, other financing activities primarily consist of debt issuance costs. See Note 11 — Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for further detailsadditional information of the Registrants’ debt issuances.
Credit Matters
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 $8.3$8.0 billion was available as of September 30, 2017,2018, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper market during the third quarter of 20172018 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 of the Exelon 20162017 Form 10-K for furtheradditional 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 September 30, 2017,2018, it would have been required to provide incremental collateral of $1.8 billion to meet collateral obligations for derivatives, non-derivatives, normal purchasepurchases and 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 $4.6$4.4 billion.

261
Table of Contents


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 September 30, 20172018 and available credit facility capacity prior to any incremental collateral at September 30, 2017:2018:
PJM Credit Policy Collateral 
Other Incremental Collateral Required (a)
 Available Credit Facility Capacity Prior to Any Incremental CollateralPJM Credit Policy Collateral 
Other Incremental Collateral Required(a)
 Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd$18
 $—
 $998
$8
 $—
 $998
PECO3
 20
 599
1
 22
 600
BGE3
 28
 600
12
 31
 599
Pepco4
 —
 300
11
 —
 296
DPL1
 9
 300
5
 10
 300
ACE—
 —
 300
—
 —
 300
_________
(a)Represents incremental collateral related to natural gas procurement contracts.
Exelon Credit Facilities
Exelon Corporate, ComEd, BGE, Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes. 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 Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
The following table reflects the Registrants’ commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at September 30, 2017:2018:
Commercial Paper Programs
Commercial Paper Issuer 
Maximum Program Size (a)(b)
 Outstanding Commercial Paper at
September 30, 2017		 Average Interest Rate on Commercial Paper Borrowings for the Nine Months Ended September 30, 2017 
Maximum Program Size(a)(b)(c)
 Outstanding Commercial Paper at
September 30, 2018		 Average Interest Rate on Commercial Paper Borrowings for the Nine Months Ended September 30, 2018
Exelon Corporate $600
 $—
 1.16% $600
 $—
 1.93%
Generation 5,300
 —
 1.20% 5,300
 —
 1.96%
ComEd 1,000
 —
 1.24% 1,000
 —
 2.14%
PECO 600
 —
 1.13% 600
 —
 2.24%
BGE 600
 —
 1.15% 600
 —
 2.15%
Pepco 500
 —
 1.04% 500
 64
 2.19%
DPL 500
 54
 1.40% 500
 —
 2.07%
ACE 350
 65
 1.36% 350
 145
 2.15%
_________
(a)Excludes $525$545 million bilateral credit facilities that do not back Generation's commercial paper program.
(b)Excludes additional$128 million of credit facility agreements forarranged at minority and community banks at Generation, PECO, ComEd, PECO, BGE, Pepco, DPL and ACEACE. These facilities expired on October 12, 2018 and were renewed with aggregate commitments of $49 million, $34$33.5 million, $34$32.5 million, $5 million, $2$5 million, $2$5 million, and $2$5 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire onthrough October 12, 2018.11, 2019. These facilities are solely utilized to issue letters of credit. As of September 30, 2017,2018, letters of credit issued under these agreements for Generation ComEd, PECO and BGE totaled $5 million, $12 million, $21 million and $2 million, respectively.

262
Table of Contents


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 its commercial paper outstanding 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 September 30, 2017, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:
Credit Agreements
Borrower Facility Type 
Aggregate Bank
Commitment(a)(b)(c)
 
Facility
Draws
 
Outstanding
Letters of
Credit
 Available Capacity at
September 30, 2017
Actual 
To Support
Additional
Commercial
Paper(b)(d)
Exelon Corporate Syndicated Revolver $600
 $—
 $45
 $555
 $555
Generation(e)
 Syndicated Revolver 5,300
 —
 887
 4,413
 4,413
Generation Bilaterals 525
 70
 235
 220
 —
ComEd Syndicated Revolver 1,000
 —
 2
 998
 998
PECO Syndicated Revolver 600
 —
 1
 599
 599
BGE Syndicated Revolver 600
 —
 —
 600
 600
Pepco Syndicated Revolver 300
 —
 —
 300
 300
DPL Syndicated Revolver 300
 —
 —
 300
 246
ACE Syndicated Revolver 300
 —
 —
 300
 235
_________
(a)Excludes $128 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of September 30, 2017, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $5 million, $12 million, $21 million and $2 million, respectively.
(b)(c)Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility

Table of Contents

maximum amount of short-term debt the Registrant is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of outstanding commercial paper does not reduce available capacity under a Registrant’s credit facility, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility. At September 30, 2018, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:
Borrower Facility Type 
Aggregate Bank
Commitment(a)
 
Facility
Draws
 
Outstanding
Letters of
Credit(c)
 Available Capacity at
September 30, 2018
Actual 
To Support
Additional
Commercial
Paper(b)
Exelon Corporate Syndicated Revolver $600
 $—
 $9
 $591
 $591
Generation Syndicated Revolver 5,300
 —
 1,139
 4,161
 4,161
Generation Bilaterals 545
 —
 356
 189
 —
ComEd Syndicated Revolver 1,000
 —
 2
 998
 998
PECO Syndicated Revolver 600
 —
 —
 600
 600
BGE Syndicated Revolver 600
 —
 1
 599
 599
Pepco Syndicated Revolver 300
 —
 4
 296
 232
DPL Syndicated Revolver 300
 —
 —
 300
 300
ACE Syndicated Revolver 300
 —
 —
 300
 155
_________
(c)(a)Excludes $128 million of credit facility agreements arranged at minority and community banks at Generation, PECO, ComEd, BGE, Pepco, DPL and ACE. These facilities expired on October 12, 2018 and were renewed with aggregate commitments of $49 million, $33.5 million, $32.5 million, $5 million, $5 million, $5 million, and $5 million, respectively, through October 11, 2019. These facilities are solely utilized to issue letters of credit. As of September 30, 2018, letters of credit issued under these agreements for Generation and BGE totaled $5 million and $2 million, respectively. Excludes nonrecourse debt letters of credit, see Note 1413 — Debt and Credit Agreements in the Exelon 20162017 Form 10-K for further information on Continental Wind nonrecourse debt.additional information.
(d)(b)Excludes $525$545 million bilateral credit facilities that do not back Generation’s commercial paper program.
(e)Excludes ExGen Texas Power Financing's $20 million of borrowed debt on its revolving credit facility.
As of September 30, 2017,2018, there was $70 million ofwere no borrowings under Generation's bilateral credit facilities.
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:
Exelon Generation ComEd PECO BGE Pepco DPL ACEExelon Corporate Generation ComEd PECO BGE Pepco DPL ACE
Prime based borrowings27.5 27.5 7.5 0.0 0.0 7.5
 7.5
 7.5
27.5 27.5 7.5 0.0 0.0 7.5
 7.5
 7.5
LIBOR-based borrowings127.5 127.5 107.5 90.0 100.0 107.5
 107.5
 107.5
127.5 127.5 107.5 90.0 100.0 107.5
 107.5
 107.5

Table of Contents

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.

263
Table of Contents


Each revolving credit agreement for Exelon Corporate, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The following table summarizes the minimum thresholds reflected in the credit agreements for the nine months ended September 30, 2017:2018:
 Exelon Corporate Generation ComEd PECO BGE Pepco DPL ACE
Credit agreement threshold2.50 to 1 3.00 to 1 2.00 to 1 2.00 to 1 2.00 to 1 2.00 to 1 2.00 to 1 2.00 to 1
At September 30, 2017,2018, the interest coverage ratios at Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACEthe Registrants were as follows:
 Exelon Generation ComEd PECO BGE Pepco DPL ACE
Interest coverage ratio6.27
 9.02
 10.83
 8.26
 10.66
 6.83 8.78 6.03
 Exelon Generation ComEd PECO BGE Pepco DPL ACE
Interest coverage ratio6.87
 11.16
 12.28
 7.86
 9.32
 5.81 7.53 5.30
An event of default under Exelon, Generation, ComEd, PECO or BGE's indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation will constitute an event of default under the Exelon Corporate credit facility. An event of default under Pepco, DPL or ACE's indebtedness will not constitute an event of default under any ofwith respect to the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $50 million in the aggregate will constitute an event of defaultPHI Utilities under the PHI Utilities' combined credit facility.
The absence of a material adverse change in Exelon's or PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under any of the borrowers' credit agreement. None of the credit agreement. The credit agreement does notagreements include any rating triggers.
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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

264
Table of Contents


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 pools.pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of September 30, 2017,2018, are presented in the following table:
Exelon Intercompany Money Pool During the Three Months Ended September 30, 2017 As of September 30, 2017 During the Three Months Ended September 30, 2018 As of September 30, 2018
Contributed (borrowed) 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
Contributed (Borrowed) 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
Exelon Corporate $579
 n/a
 $280
 $316
 $—
 $167
Generation —
 (417) (146) 227
 —
 —
PECO 97
 (10) 57
 —
 (276) —
BSC —
 (369) (245) —
 (329) (214)
PHI Corporate (a)

 n/a
 (33) (1)
PHI Corporate —
 (18) (10)
PCI (a)
 54
 —
 54
 57
 (1) 57
_________
(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 During the Three Months Ended September 30, 2017 As of September 30, 2017 During the Three Months Ended September 30, 2018 As of September 30, 2018
Contributed (borrowed) 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
Contributed (Borrowed) 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
PHI Corporate $51
 $(1) $—
 $26
 $—
 $1
PHISCO 24
 (25) —
 3
 (23) 2
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 13 —Nuclear Decommissioning—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for furtheradditional information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.
Shelf Registration Statements
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2019. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

265
Table of Contents


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)(b)
 
Long-term Financing Authority(c)
 As of September 30, 2018
Commission Expiration Date Amount (in millions)Commission Expiration Date Amount (in millions) 
Short-term Financing Authority(a)
 
Remaining Long-term Financing Authority(a)
ComEd(d)
 FERC December 31, 2017 $2,500
 ICC 2019 $1,383
PECO FERC December 31, 2017 1,500
 PAPUC December 31, 2018 1,275
 Commission Expiration Date Amount Commission Expiration Date Amount
FERC December 31, 2019 $2,500
ICC 2019 & 2021 $1,533
PECO(c)
 FERC December 31, 2019 1,500
 PAPUC December 31, 2018 575
BGE FERC December 31, 2017 700
 MDPSC N/A 700
 FERC December 31, 2019 700
 MDPSC N/A 400
Pepco FERC June 30, 2018 500
 MDPSC / DCPSC September 25, 2017 —
 FERC December 31, 2019 500
 MDPSC / DCPSC December 31, 2020 500
DPL FERC June 30, 2018 500
 MDPSC / DPSC December 31, 2017 125
 FERC December 31, 2019 500
 MDPSC / DPSC December 31, 2020 150
ACE NJPU January 1, 2018 350
 NJBPU December 31, 2017 300
ACE(d)
 NJBPU December 31, 2019 350
 NJBPU December 31, 2019 350
_________
(a)Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.
(b)On October 31, 2017, ComEd PECO, BGE, Pepcohad $440 million available in long-term debt refinancing authority and DPL filed applications with FERC for renewal of their short-term$1,093 million available in new money long-term debt financing authority through December 31, 2019. ComEd, PECO, BGE, Pepcofrom the ICC as of September 30, 2018 and DPL expect approvalhas an expiration date of the applications before the end of the year.June 1, 2019 and August 1, 2021, respectively.
(c)Pepco, DPL, and ACE, arePECO is currently in the process renewing theirits long-term financing authority with their respective commissionsPAPUC and expect approvalsexpects approval before the end of the year.
(d)ComEd had $1,140 million available inAs a result of the October 16, 2018 debt issuance, the remaining long-term debt refinancing authority and $243 million available in new money long term debt financing authority fromat ACE is zero. See Note 11 — Debt and Credit Agreements of the ICC as of September 30, 2017 and has an expiration date of June 1, 2019 and March 1, 2019, respectively.Combined Notes to Consolidated Financial Statements for additional information regarding ACE debt issuance.

Contractual Obligations and Off-Balance Sheet Arrangements
Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 2423 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 20162017 Form 10-K.
Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 — Basis of PresentationSignificant Accounting Policies of the Combined Notes to Consolidated Financial Statements for furtheradditional information.
For an in-depth discussion of the Registrants' contractual obligations and off-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in the Exelon 20162017 Form 10-K and "Management's Discussion and Analysis10-K.

Table of Financial Condition and Results of Operations - Contractual Obligations and Commercial Commitments."Contents

Item 3.    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. The following discussion serves as an update to ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of Exelon’s 20162017 Annual Report on Form 10-K incorporated herein by reference.
Commodity Price Risk (All Registrants)
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies and other factors. To the extent the total amount of energy Exelon generates and purchases differs from the amount of energy it has contracted to sell, Exelon has price risk fromis exposed to market fluctuations in commodity price movements.prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel and other commodities.

266
Table of Contents


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 commodity price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including forwards,swaps, futures, swapsforwards and options, with approved counterparties to hedge anticipated exposures. Generation believes theseuses derivative instruments representas economic hedges thatto mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 20172018 through 2019.2020.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Exelon's hedging program involves the hedging of commodity price risk for Exelon's expected generation, typically on a ratable basis over a three-year period.periods. As of September 30, 2017,2018, the percentage of expected generation hedged is 98%-101%, 79%-82%82%-85% and 45%-48%48%-51% for 2017, 2018, 2019 and 2019,2020, 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 the Utility RegistrantsComEd, PECO and BGE to serve their retail load.
A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire non-proprietary tradingeconomic hedge portfolio associated with a $5$5 reduction in the annual average around-the-clock energy price based on September 30, 20172018 market conditions and hedged position would be an increase in pre-tax net income of approximately $10approximately $11 million for 20172018 and decreases of approximately $170$150 million and $500$475 million, respectively, for 20182019 and 2019.2020. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs

Table of Contents

constant. Generation expects to actively managemanages its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Retail Competition
Constellation competes for retail 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 hedge generation output. Increased or more aggressive competition could adversely affect Generation's overall gross margins and profitability.
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 2,601 GWhs and 6,763 GWhs for the three and nine months ended September 30, 2017, respectively, and 1,506 GWhs and 4,015 GWhs and for the three and nine months September 30, 2016, respectively, are a complement to Generation’s energy marketing portfolio, but represent a small portion of Generation’s overall revenue from energy marketing activities. Activities
Proprietary trading portfolio activity for the nine months ended September 30, 20172018 resulted in $11$39 million of pre-tax gains due to net mark-to-market gains of $3$14 million and realized gains of $8$25 million. Generation uses a 95% confidence interval, assuming standard normal distribution, one day holding period and a one-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged $0.1 million of exposure during the quarter. 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 expenseexpense. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for the nine months ended September 30, 2017 of $6,526 million.additional information.
Fuel Procurement.Procurement
Generation procures natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 60%59% of Generation’s uranium concentrate requirements

267
Table of Contents


from 20172018 through 20212022 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.
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
ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which is further discussed in Note 56 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. The block energy contracts are considered derivatives and qualify for the normal purchases and normal sales scope exception under current

Table of Contents

derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. ComEd does not enter into derivatives for speculative or proprietary trading purposes. See Note 10 — 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.
PECOon these contracts.
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 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. PECO hasBGE, Pepco, DPL and ACE
BGE, Pepco, DPL and ACE have certain full requirements contracts, which are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. Under the DSP Programs, PECO is permitted to recover its electric supply procurement costs from retail customers with no mark-up.Other full requirements contracts are not derivatives.
PECO, hasBGE and DPL have also entered intoexecuted 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 itstheir 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 10 — 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.
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 programprograms for natural gas procurement hashave no direct impact on BGE’stheir results of operations or 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
PECO, BGE, Pepco, DPL 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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
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

268
Table of Contents


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 10 — 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 doesACE do not enter into derivatives for speculative or proprietary trading purposes. See Note 10 — 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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.contracts.
Trading and Non-Trading Marketing Activities.Activities
 The following detailed presentation oftables detail 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).

269
Table of Contents


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 December 31, 20162017 to September 30, 2017.2018. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all normal purchase and normal salesNPNS contracts and does not segregate proprietary trading activity. See Note 10 — 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 September 30, 20172018 and December 31, 2016.2017.
 Exelon Generation ComEd PHI DPL
Total mark-to-market energy contract net assets (liabilities) at December 31, 2016(a)
$719
 $977
 $(258) $—
 $—
Total change in fair value during 2017 of contracts recorded in results of operations(13) (13) —
 —
 —
Reclassification to realized of contracts recorded in results of operations(138) (138) —
 —
 —
Contracts received at acquisition date—
 —
 —
 —
 —
Changes in fair value — recorded through regulatory assets and liabilities(b)
(21) —
 (19) (2) (2)
Changes in allocated collateral88
 86
 —
 2
 2
Changes in net option premium paid/(received)(35) (35) —
 —
 —
Option premium amortization(15) (15) —
 —
 —
Upfront payments and amortizations(c)
(54) (54) —
 —
 —
Total mark-to-market energy contract net assets (liabilities) at September 30, 2017(a)
$531
 $808
 $(277) $—
 $—
 Exelon Generation ComEd PHI DPL
Total mark-to-market energy contract net assets (liabilities) at December 31, 2017(a)
$667
 $923
 $(256) $—
 

Total change in fair value during 2018 of contracts recorded in results of operations385
 385
 —
 —
 —
Reclassification to realized of contracts recorded in results of operations(474) (474) —
 —
 —
Changes in fair value — recorded through regulatory assets and liabilities(b)
(2) —
 (3) 1
 1
Changes in allocated collateral(255) (254) —
 (1) (1)
Net option premium paid/(received)36
 36
 —
 —
 —
Option premium amortization(4) (4) —
 —
 —
Upfront payments and amortizations(28) (28) —
 —
 —
Total mark-to-market energy contract net assets (liabilities) at September 30,2018(a)
$325
 $584
 $(259) $—
 $—
_________
(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 September 30, 2017,2018, ComEd recorded a regulatory liability of $277$259 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the nine months ended September 30, 2017,2018, ComEd also recorded $32$9 million of decreases in fair value and an increase for realized losses due to settlements of $13$12 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortization.
Fair Values.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 9 — 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.

270
Table of Contents


Exelon
Maturities Within Total Fair
Value		Maturities Within Total Fair
Value
2017 2018 2019 2020 2021 2022 and Beyond 2018 2019 2020 2021 2022 2023 and Beyond 
Normal Operations, Commodity derivative contracts(a)(b):
                          
Actively quoted prices (Level 1)$27
 $1
 $(29) $(13) $2
 $(2) $(14)$7
 $(44) $(39) $(6) $(9) $13
 $(78)
Prices provided by external sources (Level 2)112
 109
 7
 (6) 5
 —
 227
91
 37
 14
 7
 1
 —
 150
Prices based on model or other valuation methods (Level 3)(c)
47
 339
 111
 18
 (32) (165) 318
1
 353
 71
 (25) (61) (86) 253
Total$186
 $449
 $89
 $(1) $(25) $(167) $531
$99
 $346
 $46
 $(24) $(69) $(73) $325
_________
(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 $415$212 million at September 30, 2017.2018.
(c)Includes ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Generation
Maturities Within Total Fair
Value		Maturities Within Total Fair
Value
2017 2018 2019 2020 2021 2022 and Beyond 2018 2019 2020 2021 2022 2023 and Beyond 
Normal Operations, Commodity derivative contracts(a)(b):
                          
Actively quoted prices (Level 1)$27
 $1
 $(29) $(13) $2
 $(2) $(14)$7
 $(44) $(39) $(6) $(9) $13
 $(78)
Prices provided by external sources (Level 2)112
 109
 7
 (6) 5
 —
 227
91
 37
 14
 7
 1
 —
 150
Prices based on model or other valuation methods (Level 3)53
 360
 133
 40
 (11) 20
 595
9
 377
 96
 —
 (36) 66
 512
Total$192
 $470
 $111
 $21
 $(4) $18
 $808
$107
 $370
 $71
 $1
 $(44) $79
 $584
_________
(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 $415$212 million at September 30, 2017.2018.
ComEd
Maturities Within Total Fair
Value		Maturities Within Total Fair
Value
2017 2018 2019 2020 2021 2022 and Beyond 2018 2019 2020 2021 2022 2023 and Beyond 
Commodity derivative contracts(a):
                          
Prices based on model or other valuation methods (Level 3)$(6) $(21) $(22) $(22) $(21) $(185) $(277)$(8) $(24) $(25) $(25) $(25) $(152) $(259)
_________
(a)Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

Table of Contents

Credit Risk, Collateral and Contingent RelatedContingent-Related Features (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter intoexecute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussioninformation of credit risk, collateral and contingent relatedcontingent-related features.

271
Table of Contents


Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchasepurchases and normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2017.2018. The tables further delineatedisaggregate 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, NASDAQ, NGX 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 $18$47 million, $22$26 million, $2223 million, $34$39 million, $12$8 million and $7$6 million as of September 30, 2017,2018, respectively.
Rating as of September 30, 2017 Total  Exposure Before Credit Collateral 
Credit
Collateral(a)
 
Net
Exposure
 
Number of
Counterparties
Greater than 10%
of Net Exposure
 
Net Exposure of
Counterparties
Greater than
10% of Net
Exposure
Rating as of September 30, 2018 Total  Exposure Before Credit Collateral 
Credit
Collateral(a)
 
Net
Exposure
 
Number of
Counterparties
Greater than 10%
of Net Exposure
 
Net Exposure of
Counterparties
Greater than
10% of Net
Exposure
Investment grade $828
 $9
 $819
 1
 $278
 $647
 $—
 $647
 1
 $176
Non-investment grade 44
 4
 40
 

 

 101
 20
 81
 

 

No external ratings                    
Internally rated — investment gradeInternally rated — investment grade316
 —
 316
 

 

 179
 1
 178
 

 

Internally rated — non-investment gradeInternally rated — non-investment grade100
 18
 82
 

 

 139
 17
 122
 

 

Total $1,288
 $31
 $1,257
 1
 $278
 $1,066
 $38
 $1,028
 1
 $176
Maturity of Credit Risk Exposure Maturity of Credit Risk Exposure
Rating as of September 30, 2017
Less than
2 Years
 2-5 Years 
Exposure
Greater than
5 Years
 
Total Exposure
Before Credit
Collateral
Rating as of September 30, 2018 
Less than
2 Years
 2-5 Years 
Exposure
Greater than
5 Years
 
Total Exposure
Before Credit
Collateral
Investment grade$682
 $139
 $7
 $828
 $615
 $30
 $2
 $647
Non-investment grade36
 8
 —
 44
 104
 (3) —
 101
No external ratings               
Internally rated — investment grade249
 35
 32
 316
 120
 30
 29
 179
Internally rated — non-investment grade87
 13
 —
 100
 129
 10
 —
 139
Total$1,054
 $195
 $39
 $1,288
 $968
 $67
 $31
 $1,066

Table of Contents

Net Credit Exposure by Type of CounterpartyAs of
September 30, 2017		 As of
September 30, 2018
Financial institutions$48
 $19
Investor-owned utilities, marketers, power producers538
 572
Energy cooperatives and municipalities525
 357
Other146
 80
Total$1,257
 $1,028
_________
(a)As of September 30, 2017,2018, credit collateral held from counterparties where Generation had credit exposure included $19$4 million of cash and $12$34 million of letters of credit.
ComEd, PECO, BGE, PHI, Pepco, DPL and ACEThe Utility Registrants
There have been no significant changes or additions to ComEd’s, PECO's, BGE's, PHI's, Pepco's, DPL's or ACE'sthe Utility Registrants exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 20162017 Annual Report on Form 10-K.
See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding credit exposure to suppliers.

272
Table of Contents


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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. See Note 17 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.
Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial position.positions. 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 toTo post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 2. Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information.
As of September 30, 2017, Generation had cash collateral of $460 million posted and cash collateral held of $49 million for external counterparties with derivative positions, of which $415 million amount in net cash collateral deposits and $1 million amount in net cash collateral receipts were offset against energy derivative and interest rate and foreign exchange derivative related to underlying energy contracts, respectively. As of September 30, 2017, $3 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. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.
ComEdThe Utility Registrants
As of September 30, 2017,2018, ComEd held $10$6 million in collateral from suppliers in association with energy procurement contracts, and held approximately $21$20 million in the form of cashcollateral from suppliers for REC and letters of creditZEC contract obligations and $19 million in collateral from suppliers for both annual and long-term renewable energy contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements in this report and Note 3 — Regulatory Matters of the 2016 Exelon Form 10-K for additional information.
PECO
As of September 30, 2017, PECO was not required to post collateral under its energy and natural gas procurement contracts. See Note 10 — 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 norbut was it holding an immaterial amount of collateral under its electric supply procurement contracts as of September 30, 2017. As of September 30, 2017,contracts. BGE was not required to post collateral

Table of Contents

under its natural gas procurement contracts but was holding an immaterial amount of collateral under its natural gas procurement contracts. PECO, Pepco, DPL and ACE were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 6 — Regulatory Matters and Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

273
Table of Contents


Pepco
Pepco is not required to post collateral under its energy procurement contracts. See Note 10 — 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 September 30, 2017, DPL was not required to post collateral under its natural gas procurement contracts. See Note 10 — 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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
RTOs andand ISOs (All Registrants)
Generation, ComEd, PECO, BGE, Pepco, DPL and ACEAll Registrants participate in all, or some, of the established wholesale spot energy markets that are administered by PJM, ISO-NE, ISO-NY, CAISO, MISO, SPP, AESO, OIESO and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there are no spot energy markets, electricity is purchased and sold solely through bilateral agreements. For sales into the spot energy markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ results of operations, cash flows and financial positions.
Exchange Traded Transactions (Exelon, Generation, PHI and DPL)
Generation enters into commodity transactions on NYMEX, ICE, NASDAQ, NGX and the Nodal exchange ("the Exchanges"). DPL enters into commodity transactions on ICE. The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on the Exchanges are significantly collateralized and have limited counterparty credit risk.
Interest Rate and Foreign Exchange Risk (All Registrants)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize 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 September 30, 2017,2018, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had $491$622 million of notional amounts of floating-to-fixed hedges outstanding. Assuming the interest rate hedges are 100% effective, aA hypothetical 50 bpsbasis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $4 million decrease in Exelon Consolidated pre-tax income for the nine months ended September 30, 2017.2018. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Equity Price Risk (Exelon and Generation)
Exelon and Generation maintainsmaintain trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of September 30, 2017,2018, 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.

274
Table of Contents


investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $626$557 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 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussionadditional information of equity price risk as a result of the current capital and credit market conditions.
Item 4.    Controls and Procedures
During the third quarter of 2017,2018, each of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by all Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to Exelon’s management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of September 30, 2017,2018, the principal executive officer and principal financial officer of each of Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. All Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There have been no changes in internal control over financial reporting that occurred during the third quarter of 20172018 that have materially affected, or are reasonably likely to materially affect, any of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and ACE’s internal control over financial reporting.

275
Table of Contents


PART II — OTHER INFORMATION
Item 1.    Legal Proceedings
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s 20162017 Form 10-K and (b) Notes 56 —Regulatory Matters and 1817 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.
Item 1A.    Risk Factors
Risks Related to Exelon
At September 30, 2017,2018, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 20162017 Form 10-K in ITEM 1A. RISK FACTORS.
Item 4.    Mine Safety Disclosures
All Registrants
Not applicable to the Registrants.

Table of Contents

Item 6.    Exhibits
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 registrantRegistrant and its subsidiaries on a consolidated basis and the relevant registrantRegistrant agrees to furnish a copy of any such instrument to the Commission upon request.
Exhibit
No.
Description
3.1
Amended and Restated Articles of Incorporation of Exelon Corporation (File No. 001-16169, Form 8-K dated July 27, 2018, Exhibit 3.1)
3.2
Amended and Restated Bylaws of Exelon Corporation (File No. 001-16169, Form 8-K dated July 27, 2018, Exhibit 3.2)
4.1
Supplemental Indenture dated as of August 9, 2017,July 26, 2018 from ComEdCommonwealth Edison Company to BNY Mellon Trust Company of Illinois, as trustee, and D. G. Donovan, as co-trustee (File No. 001-01839, Form 8-K dated August 23, 2017,14, 2018, Exhibit 4.1)


  
4.2
BGE Form of 3.750% notes due 2047 (File No. 001-01910, Form 8-K dated August 24, 2017, Exhibit 4.1)
4.3
One Hundred and Fourteenth Supplemental Indenture dated as of September 1, 2017,2018 from PECO Energy Company to U.S. Bank National Association, as trustee (File No. 000-16844, Form 8-K dated September 18, 2017,11, 2018, Exhibit 4.1)

4.3
Supplemental Indenture dated as of October 9, 2018 from Atlantic City Electric Company to The Bank of New York Mellon, as trustee (File No. 001-03559, Form 8-K dated October 16, 2018, Exhibit 4.1)
  
101.INSXBRL Instance
  
101.SCHXBRL Taxonomy Extension Schema
  
101.CALXBRL Taxonomy Extension Calculation
�� 
101.DEFXBRL Taxonomy Extension Definition
  
101.LABXBRL Taxonomy Extension Labels
  
101.PREXBRL Taxonomy Extension Presentation

276
Table of Contents


Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 20172018 filed by the following officers for the following companies:
31-1
— Filed by Christopher M. Crane for Exelon Corporation
  
31-2
— Filed by Jonathan W. ThayerJoseph Nigro for Exelon Corporation
  
31-3
— Filed by Kenneth W. Cornew for Exelon Generation Company, LLC
  
31-4
— Filed by Bryan P. Wright for Exelon Generation Company, LLC
  
31-5
— Filed by Anne R. PramaggioreJoseph Dominguez for Commonwealth Edison Company
  
31-6
— Filed by Joseph R. Trpik, Jr.Jeanne M. Jones for Commonwealth Edison Company
  
31-7
— Filed by Craig L. AdamsMichael A. Innocenzo for PECO Energy Company
  
31-8
— Filed by Phillip S. BarnettRobert J. Stefani for PECO Energy Company
  
31-9
— Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company
  
31-10
— Filed by David M. Vahos for Baltimore Gas and Electric Company
  
31-11
— Filed by David M. Velazquez for Pepco Holdings LLC
  
31-12
— Filed by Donna J. KinzelPhillip S. Barnett for Pepco Holdings LLC
  
31-13
— Filed by David M. Velazquez for Potomac Electric Power Company
  
31-14
— Filed by Donna J. KinzelPhillip S. Barnett for Potomac Electric Power Company
  
31-15
— Filed by David M. Velazquez for Delmarva Power & Light Company
  
31-16
— Filed by Donna J. KinzelPhillip S. Barnett for Delmarva Power & Light Company
  
31-17
— Filed by David M. Velazquez for Atlantic City Electric Company
  
31-18
— Filed by Donna J. KinzelPhillip S. Barnett for Atlantic City Electric Company

277
Table of Contents


Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 20172018 filed by the following officers for the following companies:
  
32-1
— Filed by Christopher M. Crane for Exelon Corporation
  
32-2
— Filed by Jonathan W. ThayerJoseph Nigro for Exelon Corporation
  
32-3
— Filed by Kenneth W. Cornew for Exelon Generation Company, LLC
  
32-4
— Filed by Bryan P. Wright for Exelon Generation Company, LLC
  
32-5
— Filed by Anne R. PramaggioreJoseph Dominguez for Commonwealth Edison Company
  
32-6
— Filed by Joseph R. Trpik, Jr.Jeanne M. Jones for Commonwealth Edison Company
  
32-7
— Filed by Craig L. AdamsMichael A. Innocenzo for PECO Energy Company
  
32-8
— Filed by Phillip S. BarnettRobert J. Stefani for PECO Energy Company
  
32-9
— Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company
  
32-10
— Filed by David M. Vahos for Baltimore Gas and Electric Company
  
32-11
— Filed by David M. Velazquez for Pepco Holdings LLC
  
32-12
— Filed by Donna J. KinzelPhillip S. Barnett for Pepco Holdings LLC
  
32-13
— Filed by David M. Velazquez for Potomac Electric Power Company
  
32-14
— Filed by Donna J. KinzelPhillip S. Barnett for Potomac Electric Power Company
  
32-15
— Filed by David M. Velazquez for Delmarva Power & Light Company
  
32-16
— Filed by Donna J. KinzelPhillip S. Barnett for Delmarva Power & Light Company
  
32-17
— Filed by David M. Velazquez for Atlantic City Electric Company
  
32-18
— Filed by Donna J. KinzelPhillip S. Barnett for Atlantic City Electric Company

278

SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON CORPORATION
 
/s/    CHRISTOPHER M. CRANE
 
/s/    JONATHAN W. THAYEROSEPH NIGRO
Christopher M. Crane Jonathan W. ThayerJoseph Nigro
President and Chief Executive Officer
(Principal Executive Officer) and Director
 
Senior Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
   
/s/    DFUANEABIAN M. DE. SESPARTEOUZA
  
Duane M. DesParteFabian E. Souza  
Senior Vice President and Corporate Controller
(Principal Accounting Officer)
  
November 2, 20171, 2018


279

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON GENERATION COMPANY, LLC
 
/s/    KENNETH W. CORNEW
 
/s/    BRYAN P. WRIGHT
Kenneth W. Cornew Bryan P. Wright
President and Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
   
/s/    MATTHEW N. BAUER
  
Matthew N. Bauer  
Vice President and Controller
(Principal Accounting Officer)
  
November 2, 20171, 2018


280

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
COMMONWEALTH EDISON COMPANY
 
/s/    AJNNEOSEPH R. PDRAMAGGIOREOMINGUEZ
 
/s/    JOSEPHEANNE R. TRPIK,M. JR.ONES
Anne R. PramaggioreJoseph Dominguez Joseph R. Trpik, Jr.Jeanne M. Jones
President and Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
   
/s/    GERALD J. KOZEL
  
Gerald J. Kozel  
Vice President and Controller
(Principal Accounting Officer)
  
November 2, 20171, 2018


281

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PECO ENERGY COMPANY
 
/s/    CMRAIGICHAEL L. AA. IDAMSNNOCENZO
 
/s/    PRHILLIPOBERT  S. BJ. SARNETTTEFANI
Craig L. AdamsMichael A. Innocenzo Phillip S. BarnettRobert J. Stefani
President and Chief Executive Officer
(Principal Executive Officer) and Director
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
   
/s/    SCOTT A. BAILEY
  
Scott A. Bailey  
Vice President and Controller
(Principal Accounting Officer)
  
November 2, 20171, 2018


282

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
 
/s/    CALVIN G. BUTLER, JR.
 
/s/    DAVID M. VAHOS
Calvin G. Butler, Jr. David M. Vahos
Chief Executive Officer
(Principal Executive Officer)
 Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
   
 /s/ ANDREW W. HOLMES
  
Andrew W. Holmes  
Vice President and Controller
(Principal Accounting Officer)
  
November 2, 20171, 2018


283

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

/s/ DAVID M. VELAZQUEZ
 
/s/    DPONNAHILLIP J. KS. BINZELARNETT
David M. Velazquez Donna J. KinzelPhillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
   
/s/ ROBERT M. AIKEN
  
Robert M. Aiken  
Vice President and Controller
(Principal Accounting Officer)
  
November 2, 20171, 2018


284

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

/s/ DAVID M. VELAZQUEZ
 
/s/    DPONNAHILLIP J. KS. BINZELARNETT
David M. Velazquez Donna J. KinzelPhillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)		 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
   
/s/ ROBERT M. AIKEN
  
Robert M. Aiken  
Vice President and Controller
(Principal Accounting Officer)		  
November 2, 20171, 2018


285

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

/s/ DAVID M. VELAZQUEZ
 
/s/    DPONNAHILLIP J. KS. BINZELARNETT
David M. Velazquez Donna J. KinzelPhillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)		 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
   
/s/ ROBERT M. AIKEN
  
Robert M. Aiken  
Vice President and Controller
(Principal Accounting Officer)		  
November 2, 20171, 2018


286

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

/s/ DAVID M. VELAZQUEZ
 
/s/    DPONNAHILLIP J. KS. BINZELARNETT
David M. Velazquez Donna J. KinzelPhillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)		 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
   
/s/ ROBERT M. AIKEN
  
Robert M. Aiken  
Vice President and Controller
(Principal Accounting Officer)		  
November 2, 20171, 2018

287309