false(800)(202)(410)(312)(202)(610)(215)(202)(202)--12-31Q3201910 South Dearborn Street500 North Wakefield Drive2 Center Plaza440 South LaSalle Street500 North Wakefield Drive300 Exelon WayP.O. Box 8699701 Ninth Street, N.W.701 Ninth Street, N.W.P.O. Box 805379110 West Fayette Street2301 Market StreetChicagoNewarkBaltimoreChicagoNewarkKennett SquarePhiladelphiaWashington, District of ColumbiaWashington, District of Columbia60680-53791970221201-370860605-10281970219348-247319101-86992006820068ILDEMDILDEPAPA000110935700000081920000009466000002260600000278790001168165000007810000011359710000079732PANJMDILDEVAPAPADEDCVA483-3220872-2000234-5000394-4321872-2000765-5959841-4000872-2000872-2000Common stock, without par valueCumulative Preferred Security, Series DNasdaq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years5 years30 years3 years30 years3 years30 years3 years5 years5 years30 years3 years3 years3 years4 years4 years2 years2 years14 years2 yearsP8YP1YP87YP1YP6YP1YP13YP1YP37YP1YP15YP1YP13YP1YP13YP1YP87YP1Y79 years5 years5 years1 years50 years5 years5 years5 years79 years1 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 0001109357 exc:PepcoHoldingsLLCMember srt:MaximumMember 2019-01-01OysterCreekMember us-gaap:OperatingExpenseMember 2019-04-01 2019-06-30 0001109357 exc:ExelonGenerationCoLLCMember exc:CommodityDerivativeAssetsMember us-gaap:FairValueInputsLevel2Member exc:CommodityDerivativeLiabilitesMemberFairValueMeasuredAtNetAssetValuePerShareMember us-gaap:FairValueMeasurementsRecurringMember 2018-12-31 0001109357 srt:MaximumMemberexc:ExelonGenerationCoLLCMember exc:RabbiTrustInvestmentsMember us-gaap:DerivativeMemberFairValueMeasuredAtNetAssetValuePerShareMember us-gaap:FairValueInputsLevel3MemberFairValueMeasurementsRecurringMember 2019-09-30 0001109357 exc:OptionModelValuationTechniqueMember 2018-12-31GenerationErcotMember 2019-01-01 2019-09-30 0001109357 exc:BaltimoreGasAndElectricCompanyMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityUsRegulatedMember exc:PepcoHoldingsLLCMember 2018-04-01 2018-06-30 0001109357 exc:CommonwealthEdisonCoMember exc:SmallCommercialIndustrialMember us-gaap:NaturalGasUsRegulatedMember exc:RateRegulatedNaturalGasRevenuesMember 2019-01-01 2019-06-30RegulatedOperationMember 2019-07-01 2019-09-30
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended JuneSeptember 30, 2019
or
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission
File Number
 Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number IRS Employer Identification Number
     
001-16169 EXELON CORPORATION 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
  
     
001-1839001-01839 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
  
     
001-1910001-01910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
  
(a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore, Maryland 21201-3708
(410) 234-5000
  
     
001-31403 PEPCO HOLDINGS LLC 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
  


Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol(s) Name of each exchange on which registered
EXELON CORPORATION:    
Common Stock, without par value EXC New YorkThe Nasdaq Stock ExchangeandChicago Stock ExchangeMarket LLC
Series A Junior Debt Subordinated DebenturesEXC22New York Stock Exchange
     
PECO ENERGY COMPANY:    
Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company EXC/28 New York Stock Exchange

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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  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.
Exelon CorporationLarge Accelerated FilerxAccelerated Filer☐Non-accelerated Filer☐Smaller Reporting Company☐Emerging Growth Company☐
Exelon Generation Company, LLCLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Commonwealth Edison CompanyLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
PECO Energy CompanyLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Baltimore Gas and Electric CompanyLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Pepco Holdings LLCLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Potomac Electric Power CompanyLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Delmarva Power & Light CompanyLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Atlantic City Electric CompanyLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  ☐  No  x
The number of shares outstanding of each registrant’s common stock as of JuneSeptember 30, 2019 was:
Exelon Corporation Common Stock, without par value971,584,496972,108,865
Exelon Generation Company, LLCnot applicable
Commonwealth Edison Company Common Stock, $12.50 par value127,021,343
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, $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

 Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS
4
FILING FORMAT
8
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
8
WHERE TO FIND MORE INFORMATION
8
PART I.
FINANCIAL INFORMATION
9
ITEM 1.
FINANCIAL STATEMENTS
9
 
Exelon Corporation
 
 
Consolidated Statements of Operations and Comprehensive Income
10
 
Consolidated Statements of Cash Flows
11
 
Consolidated Balance Sheets
12
 
Consolidated Statements of Changes in Shareholders’ Equity
14
 
Exelon Generation Company, LLC
 
 
Consolidated Statements of Operations and Comprehensive Income
1516
 
Consolidated Statements of Cash Flows
1617
 
Consolidated Balance Sheets
1718
 
Consolidated Statements of Changes in Equity
1920
 
Commonwealth Edison Company
 
 
Consolidated Statements of Operations and Comprehensive Income
2022
 
Consolidated Statements of Cash Flows
2123
 
Consolidated Balance Sheets
2224
 
Consolidated Statements of Changes in Shareholders' Equity
2426
 
PECO Energy Company
 
 
Consolidated Statements of Operations and Comprehensive Income
2527
 
Consolidated Statements of Cash Flows
2628
 
Consolidated Balance Sheets
2729
 
Consolidated Statements of Changes in Shareholder's Equity
2931
 
Baltimore Gas and Electric Company
 
 
Statements of Operations and Comprehensive Income
3032
 
Statements of Cash Flows
3133
 
Balance Sheets
3234
 
Statements of Changes in Shareholder's Equity
3436
 
Pepco Holdings LLC
 
 
Consolidated Statements of Operations and Comprehensive Income
3537
 
Consolidated Statements of Cash Flows
3638
 
Consolidated Balance Sheets
3739
 
Consolidated Statements of Changes in Equity
3941

 Page No.
 
Potomac Electric Power Company
 
 
Statements of Operations and Comprehensive Income
4042
 
Statements of Cash Flows
4143
 
Balance Sheets
4244
 
Statements of Changes in Shareholder's Equity
4446
 
Delmarva Power & Light Company
 
 
Statements of Operations and Comprehensive Income
4547
 
Statements of Cash Flows
4648
 
Balance Sheets
4749
 
Statements of Changes in Shareholder’s Equity
4951
 
Atlantic City Electric Company
 
 
Consolidated Statements of Operations and Comprehensive Income
5052
 
Consolidated Statements of Cash Flows
5153
 
Consolidated Balance Sheets
5254
 
Consolidated Statements of Changes in Shareholder’s Equity
5456
 
Combined Notes to Consolidated Financial Statements
5557
 
1. Significant Accounting Policies
5557
 
2. Variable Interest Entities
5759
 
3. Mergers, Acquisitions and Dispositions
6263
 
4. Revenue from Contracts with Customers
6364
 
5. Leases
6465
 
6. Regulatory Matters
6869
 
7. Impairment of Long-Lived AssetsAsset Impairments
7375
 
8. Early Plant Retirements
7476
 
9. Fair Value of Financial Assets and Liabilities
7678
 
10. Derivative Financial Instruments
8789
 
11. Debt and Credit Agreements
9496
 
12. Income Taxes
9698
 
13. Nuclear Decommissioning
99101
 
14. Retirement Benefits
100103
 
15. Changes in Accumulated Other Comprehensive Income
103105
 
16. Commitments and Contingencies
106
 
17. Supplemental Financial Information
114113
 
18. Segment Information
120119

 Page No.
ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
136135
 
Exelon Corporation
136135
 
Executive Overview
136135
 
Financial Results of Operations
137136
 
Significant 2019 Transactions and Developments
140
 
Other Key Business Drivers and Management Strategies
142143
 
Critical Accounting Policies and Estimates
145146
 
Results of Operations By Registrant
146
 
Exelon Generation Company, LLC
147
 
Commonwealth Edison Company
154
 
PECO Energy Company
157
 
Baltimore Gas and Electric Company
161
 
Pepco Holdings LLC
164
 
Potomac Electric Power Company
165
 
Delmarva Power & Light Company
168
 
Atlantic City Electric Company
173
 
Liquidity and Capital Resources
177
 
Contractual Obligations and Off-Balance Sheet Arrangements
184
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
185
ITEM 4.
CONTROLS AND PROCEDURES
190
PART II.
OTHER INFORMATION
190
ITEM 1.
LEGAL PROCEEDINGS
190
ITEM 1A.
RISK FACTORS
190
ITEM 4.
MINE SAFETY DISCLOSURES
190
ITEM 5.
OTHER INFORMATION
191
ITEM 6.
EXHIBITS
191
SIGNATURES
194
 
Exelon Corporation
194
 
Exelon Generation Company, LLC
195
 
Commonwealth Edison Company
196
 
PECO Energy Company
197
 
Baltimore Gas and Electric Company
198
 
Pepco Holdings LLC
199
 
Potomac Electric Power Company
200
 
Delmarva Power & Light Company
201
 
Atlantic City Electric Company
202

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
DPL Delmarva Power & Light Company
ACE Atlantic City Electric Company
Registrants Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively
Utility Registrants ComEd, PECO, BGE, Pepco, DPL and ACE, collectively
ACE Funding or ATF Atlantic City Electric Transition Funding LLC
Antelope Valley Antelope Valley Solar Ranch One
BSC Exelon Business Services Company, LLC
CENG Constellation Energy Nuclear Group, LLC
Constellation Constellation Energy Group, Inc.
EGR IV ExGen Renewables IV, LLC
EGRP ExGen Renewables Partners, LLC
Exelon Corporate Exelon in its corporate capacity as a holding company
FitzPatrick James A. FitzPatrick nuclear generating station
PCI Potomac Capital Investment Corporation and its subsidiaries
Pepco Energy Services or PES Pepco Energy Services, Inc. and its subsidiaries
PHI Corporate PHI in its corporate capacity as a holding company
PHISCO PHI Service Company
SolGen SolGen, LLC
TMI Three Mile Island nuclear facility

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations  
Note "—" of the 2018 Form 10-K Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2018 Annual Report on Form 10-K
AESO Alberta Electric Systems Operator
AFUDC Allowance for Funds Used During Construction
AMI Advanced Metering Infrastructure
AOCI Accumulated Other Comprehensive Income (Loss)
ARC Asset Retirement Cost
ARO Asset Retirement Obligation
BGS Basic Generation Service
CERCLAComprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CES Clean Energy Standard
Clean Air Act Clean Air Act of 1963, as amended
Clean Water Act Federal Water Pollution Control Amendments of 1972, as amended
CODM Chief operating decision maker(s)
D.C. Circuit Court United States Court of Appeals for the District of Columbia Circuit
DC PLUG District of Columbia Power Line Undergrounding Initiative
DCPSC Public Service Commission of the District of Columbia
DOE United States Department of Energy
DOEE Department of Energy & Environment
DOJ United States Department of Justice
DPSC Delaware Public Service Commission
EDF Electricite de France SA and its subsidiaries
EIMA Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EPA United States Environmental Protection Agency
EPSA Electric Power Supply Association
ERCOT Electric Reliability Council of Texas
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
GSA Generation Supply Adjustment
ICC Illinois Commerce Commission
ICE Intercontinental Exchange
Illinois EPA Illinois Environmental Protection Agency
IPA Illinois Power Agency
IRC Internal Revenue Code
IRS Internal Revenue Service
ISOIndependent System Operator
ISO-NEIndependent System Operator New England Inc.

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations  
ISOIndependent System Operator
ISO-NEIndependent System Operator New England Inc.
ISO-NY Independent System Operator New York
LIBOR London Interbank Offered Rate
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
MOPR Minimum Offer Price Rule
MW Megawatt
NAAQS National Ambient Air Quality Standards
NDT Nuclear Decommissioning Trust
NEIL Nuclear Electric Insurance Limited
NERC North American Electric Reliability Corporation
NJBPU New Jersey Board of Public Utilities
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
NPNS Normal Purchase Normal Sale scope exception
NRC Nuclear Regulatory Commission
NYMEX New York Mercantile Exchange
NYPSC New York Public Service Commission
OCI Other Comprehensive Income
OIESO Ontario Independent Electricity System Operator
OPEB Other Postretirement Employee Benefits
Oyster Creek Oyster Creek Generating Station
PA DEP Pennsylvania Department of Environmental Protection
PAPUC Pennsylvania Public Utility Commission
PGCPurchased Gas Cost Clause
PG&E Pacific Gas and Electric Company
PJM PJM Interconnection, LLC
POLR Provider of Last Resort
PPA Power Purchase Agreement
PPE Property, plant and equipment
Price-Anderson Act Price-Anderson Nuclear Industries Indemnity Act of 1957
PRP Potentially Responsible Parties
PSDAR Post-Shutdown Decommissioning Activities Report
PSEG Public Service Enterprise Group Incorporated
REC Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
RNF Revenues Net of Purchased Power and Fuel Expense

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Regulatory Agreement Units Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
Rider Reconcilable Surcharge Recovery Mechanism

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
RMC Risk Management Committee
ROE Return on equity
ROU Right-of-use
RSSA Reliability Support Services Agreement
RTO Regional Transmission Organization
SEC United States Securities and Exchange Commission
SERC SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SNF Spent Nuclear Fuel
SOS Standard Offer Service
TCJA Tax Cuts and Jobs Act
Transition Bonds Transition Bonds issued by ACE Funding
Upstream Natural gas exploration and production activities
VIE Variable Interest Entity
WECC Western Electric Coordinating Council
ZEC Zero Emission Credit, or Zero Emission Certificate
ZES Zero Emission Standard

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 2018 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 22, 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,I, 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 16, 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 SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and the Registrants' website at www.exeloncorp.com. Information contained on the Registrants' website shall not be deemed incorporated into, or to be a part of, this Report.

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions, except per share data)2019 2018 2019 20182019 2018 2019 2018
Operating revenues              
Competitive businesses revenues$3,959
 $4,305
 $8,938
 $9,417
$4,499
 $4,971
 $13,436
 $14,387
Rate-regulated utility revenues3,743
 3,797
 8,247
 8,368
4,510
 4,457
 12,758
 12,824
Revenues from alternative revenue programs(13) (26) (19) (16)(80) (25) (98) (41)
Total operating revenues7,689
 8,076
 17,166
 17,769
8,929
 9,403
 26,096
 27,170
Operating expenses              
Competitive businesses purchased power and fuel2,289
 2,277
 5,493
 5,566
2,648
 2,977
 8,142
 8,542
Rate-regulated utility purchased power and fuel936
 1,038
 2,285
 2,476
1,304
 1,355
 3,589
 3,832
Operating and maintenance2,159
 2,307
 4,347
 4,691
2,072
 2,346
 6,419
 7,036
Depreciation and amortization1,079
 1,088
 2,154
 2,179
1,083
 1,105
 3,237
 3,284
Taxes other than income418
 428
 863
 874
452
 469
 1,316
 1,342
Total operating expenses6,881

7,138

15,142

15,786
7,559

8,252

22,703

24,036
Gain on sales of assets and businesses33
 4
 36
 60
(Loss) gain on sales of assets and businesses(17) (5) 19
 55
Operating income841

942

2,060

2,043
1,353

1,146

3,412

3,189
Other income and (deductions)    
 
    
 
Interest expense, net(403) (367) (800) (732)(403) (387) (1,202) (1,119)
Interest expense to affiliates(6) (6) (13) (13)(6) (6) (19) (19)
Other, net212
 44
 679
 17
158
 194
 837
 212
Total other income and (deductions)(197)
(329)
(134)
(728)(251)
(199)
(384)
(926)
Income before income taxes644
 613
 1,926
 1,315
1,102
 947
 3,028
 2,263
Income taxes144
 66
 454
 125
172
 137
 626
 262
Equity in losses of unconsolidated affiliates(6) (5) (12) (11)(170) (10) (182) (22)
Net income494

542

1,460

1,179
760

800

2,220

1,979
Net income attributable to noncontrolling interests10
 3
 69
 54
Net (loss) income attributable to noncontrolling interests(12) 67
 56
 121
Net income attributable to common shareholders$484

$539

$1,391

$1,125
$772

$733

$2,164

$1,858
Comprehensive income, net of income taxes              
Net income$494
 $542
 $1,460
 $1,179
$760
 $800
 $2,220
 $1,979
Other comprehensive (loss) income, net of income taxes       
Other comprehensive income (loss), net of income taxes       
Pension and non-pension postretirement benefit plans:              
Prior service benefit reclassified to periodic benefit cost(16) (17) (32) (33)(16) (17) (49) (50)
Actuarial loss reclassified to periodic benefit cost36
 61
 74
 123
37
 62
 111
 186
Pension and non-pension postretirement benefit plan valuation adjustment—
 (1) (39) 18
6
 5
 (32) 22
Unrealized gain on cash flow hedges—
 4
 —
 12
—
 —
 —
 12
Unrealized (loss) gain on investments in unconsolidated affiliates(2) 2
 (4) 3
Unrealized gain (loss) on foreign currency translation3
 (5) 4
 (6)
Unrealized gain on investments in unconsolidated affiliates5
 —
 1
 3
Unrealized (loss) gain on foreign currency translation(2) 2
 2
 (4)
Other comprehensive income21

44

3

117
30

52

33

169
Comprehensive income515

586

1,463

1,296
790

852

2,253

2,148
Comprehensive income attributable to noncontrolling interests9
 4
 67
 56
Comprehensive (loss) income attributable to noncontrolling interests(9) 67
 57
 123
Comprehensive income attributable to common shareholders$506
 $582
 $1,396
 $1,240
$799
 $785
 $2,196
 $2,025
              
Average shares of common stock outstanding:              
Basic972
 967
 972
 967
973
 968
 972
 967
Assumed exercise and/or distributions of stock-based awards2
 2
 1
 1
1
 2
 1
 2
Diluted(a)
974
 969
 973
 968
974
 970
 973
 969
              
Earnings per average common share:              
Basic$0.50
 $0.56
 $1.43
 $1.16
$0.79
 $0.76
 $2.23
 $1.92
Diluted$0.50
 $0.56
 $1.43
 $1.16
$0.79
 $0.76
 $2.22
 $1.92
__________
(a)The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was immaterial for the three and sixnine months ended JuneSeptember 30, 2019 and approximately 2 million and 53 million for the three and sixnine months ended JuneSeptember 30, 2018, respectively.

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities      
Net income$1,460
 $1,179
$2,220
 $1,979
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization2,922
 3,000
4,393
 4,511
Impairment of long-lived assets9
 41
Asset impairments174
 49
Gain on sales of assets and businesses(33) (60)(15) (55)
Deferred income taxes and amortization of investment tax credits284
 (2)412
 97
Net fair value changes related to derivatives107
 151
96
 67
Net realized and unrealized (gains) losses on NDT funds(404) 80
Net realized and unrealized gains on NDT funds(467) (21)
Other non-cash operating activities277
 479
460
 804
Changes in assets and liabilities:      
Accounts receivable618
 (105)445
 (167)
Inventories19
 60
(94) (24)
Accounts payable and accrued expenses(924) (342)(671) 84
Option premiums received (paid), net48
 (36)13
 (36)
Collateral (posted) received, net(311) 81
(254) 222
Income taxes151
 129
143
 166
Pension and non-pension postretirement benefit contributions(355) (345)(377) (362)
Other assets and liabilities(970) (441)(1,079) (639)
Net cash flows provided by operating activities2,898

3,869
5,399

6,675
Cash flows from investing activities      
Capital expenditures(3,572) (3,807)(5,259) (5,497)
Proceeds from NDT fund sales6,920
 3,822
8,443
 6,379
Investment in NDT funds(6,847) (3,924)(8,437) (6,553)
Acquisition of assets and businesses, net—
 (57)—
 (57)
Proceeds from sales of assets and businesses14
 89
17
 90
Other investing activities26
 31
21
 29
Net cash flows used in investing activities(3,459)
(3,846)(5,215)
(5,609)
Cash flows from financing activities      
Changes in short-term borrowings470
 200
430
 (218)
Proceeds from short-term borrowings with maturities greater than 90 days—
 126
—
 126
Repayments on short-term borrowings with maturities greater than 90 days(125) (1)(125) (1)
Issuance of long-term debt850
 1,488
1,576
 2,664
Retirement of long-term debt(574) (1,309)(644) (1,480)
Dividends paid on common stock(704) (666)(1,055) (999)
Proceeds from employee stock plans75
 27
94
 67
Other financing activities(34) (50)(63) (94)
Net cash flows used in financing activities(42)
(185)
Decrease in cash, cash equivalents and restricted cash(603) (162)
Net cash flows provided by financing activities213

65
Increase in cash, cash equivalents and restricted cash397
 1,131
Cash, cash equivalents and restricted cash at beginning of period1,781
 1,190
1,781
 1,190
Cash, cash equivalents and restricted cash at end of period$1,178

$1,028
$2,178

$2,321
      
Supplemental cash flow information      
Decrease in capital expenditures not paid$(133) $(283)$(96) $(175)
Increase in PPE related to ARO update301
 47
344
 67

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$735
 $1,349
$1,683
 $1,349
Restricted cash and cash equivalents252
 247
309
 247
Accounts receivable, net      
Customer (net of allowance for uncollectible accounts of $257 and $283 as of June 30, 2019 and December 31, 2018, respectively)
4,125
 4,607
Other (net of allowance for uncollectible accounts of $40 and $36 as of June 30, 2019 and December 31, 2018, respectively)
1,008
 1,256
Customer (net of allowance for uncollectible accounts of $248 and $283 as of September 30, 2019 and December 31, 2018, respectively)4,188
 4,607
Other (net of allowance for uncollectible accounts of $49 and $36 as of September 30, 2019 and December 31, 2018, respectively)1,085
 1,256
Mark-to-market derivative assets526
 804
601
 804
Unamortized energy contract assets47
 48
49
 48
Inventories, net      
Fossil fuel and emission allowances258
 334
325
 334
Materials and supplies1,412
 1,351
1,458
 1,351
Regulatory assets1,194
 1,222
1,194
 1,222
Assets held for sale880
 904
18
 904
Other1,218
 1,238
1,296
 1,238
Total current assets11,655

13,360
12,206

13,360
Property, plant and equipment (net of accumulated depreciation and amortization of $24,266 and $22,902 as of June 30, 2019 and December 31, 2018, respectively)
78,030
 76,707
Property, plant and equipment (net of accumulated depreciation and amortization of $23,590 and $22,902 as of September 30, 2019 and December 31, 2018, respectively)78,593
 76,707
Deferred debits and other assets      
Regulatory assets8,166
 8,237
8,122
 8,237
Nuclear decommissioning trust funds12,513
 11,661
12,706
 11,661
Investments618
 625
471
 625
Goodwill6,677
 6,677
6,677
 6,677
Mark-to-market derivative assets537
 452
487
 452
Unamortized energy contract assets362
 372
353
 372
Other3,038
 1,575
3,123
 1,575
Total deferred debits and other assets31,911

29,599
31,939

29,599
Total assets(a)
$121,596

$119,666
$122,738

$119,666

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY      
Current liabilities      
Short-term borrowings$1,059
 $714
$1,019
 $714
Long-term debt due within one year3,776
 1,349
4,248
 1,349
Accounts payable3,248
 3,800
3,348
 3,800
Accrued expenses1,706
 2,112
1,877
 2,112
Payables to affiliates5
 5
5
 5
Regulatory liabilities403
 644
400
 644
Mark-to-market derivative liabilities163
 475
239
 475
Unamortized energy contract liabilities145
 149
138
 149
Renewable energy credit obligation298
 344
375
 344
Liabilities held for sale764
 777
11
 777
Other1,367
 1,035
1,425
 1,035
Total current liabilities12,934
 11,404
13,085
 11,404
Long-term debt31,909
 34,075
32,056
 34,075
Long-term debt to financing trusts390
 390
390
 390
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits11,826
 11,330
12,133
 11,330
Asset retirement obligations10,023
 9,679
10,089
 9,679
Pension obligations3,720
 3,988
3,712
 3,988
Non-pension postretirement benefit obligations2,007
 1,928
2,029
 1,928
Spent nuclear fuel obligation1,186
 1,171
1,193
 1,171
Regulatory liabilities9,793
 9,559
9,792
 9,559
Mark-to-market derivative liabilities450
 479
416
 479
Unamortized energy contract liabilities398
 463
368
 463
Other3,053
 2,130
3,123
 2,130
Total deferred credits and other liabilities42,456
 40,727
42,855
 40,727
Total liabilities(a)
87,689

86,596
88,386

86,596
Commitments and contingencies

 


 

Shareholders’ equity      
Common stock (No par value, 2,000 shares authorized, 972 shares and 968 shares outstanding at June 30, 2019 and December 31, 2018, respectively)19,209
 19,116
Treasury stock, at cost (2 shares at June 30, 2019 and December 31, 2018)(123) (123)
Common stock (No par value, 2,000 shares authorized, 972 shares and 968 shares outstanding at September 30, 2019 and December 31, 2018, respectively)19,238
 19,116
Treasury stock, at cost (2 shares at September 30, 2019 and December 31, 2018)(123) (123)
Retained earnings15,452
 14,766
15,871
 14,766
Accumulated other comprehensive loss, net(2,990) (2,995)(2,963) (2,995)
Total shareholders’ equity31,548

30,764
32,023

30,764
Noncontrolling interests2,359
 2,306
2,329
 2,306
Total equity33,907

33,070
34,352

33,070
Total liabilities and shareholders’ equity$121,596

$119,666
$122,738

$119,666
__________
(a)Exelon’s consolidated assets include $9,526$9,465 million and $9,667 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,568$3,517 million and $3,548 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2 — Variable Interest Entities for additional information.

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Six Months Ended June 30, 2019Nine Months Ended September 30, 2019
(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, 2018970,020
 $19,116
 $(123) $14,766
 $(2,995) $2,306
 $33,070
970,020
 $19,116
 $(123) $14,766
 $(2,995) $2,306
 $33,070
Net income—
 —
 —
 907
 —
 59
 966
—
 —
 —
 907
 —
 59
 966
Long-term incentive plan activity2,446
 (3) —
 —
 —
 —
 (3)2,446
 (3) —
 —
 —
 —
 (3)
Employee stock purchase plan issuances320
 51
 —
 —
 —
 —
 51
320
 51
 —
 —
 —
 —
 51
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 (17) (17)—
 —
 —
 —
 —
 (17) (17)
Sale of noncontrolling interests—
 7
 —
 —
 —
 —
 7
—
 7
 —
 —
 —
 —
 7
Common stock dividends
($0.36/common share)
—
 —
 —
 (352) —
 —
 (352)—
 —
 —
 (352) —
 —
 (352)
Other comprehensive loss, net of income taxes—
 —
 —
 —
 (17) (1) (18)—
 —
 —
 —
 (17) (1) (18)
Balance, March 31, 2019972,786

$19,171

$(123)
$15,321

$(3,012)
$2,347

$33,704
972,786

$19,171

$(123)
$15,321

$(3,012)
$2,347

$33,704
Net income—
 —
 —
 484
 —
 10
 494
—
 —
 —
 484
 —
 10
 494
Long-term incentive plan activity320
 14
 —
 —
 —
 —
 14
320
 14
 —
 —
 —
 —
 14
Employee stock purchase plan issuances311
 24
 —
 —
 —
 —
 24
311
 24
 —
 —
 —
 —
 24
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 3
 3
—
 —
 —
 —
 —
 3
 3
Sale of noncontrolling interests—
 —
 —
 —
 —
 —
 —
Common stock dividends
($0.36/common share)
—
 —
 —
 (353) —
 —
 (353)—
 —
 —
 (353) —
 —
 (353)
Other comprehensive income (loss), net of income taxes—
 —
 —
 —
 22
 (1) 21
—
 —
 —
 —
 22
 (1) 21
Balance, June 30, 2019973,417
 $19,209
 $(123) $15,452
 $(2,990) $2,359
 $33,907
973,417
 $19,209
 $(123) $15,452
 $(2,990) $2,359
 $33,907
Net income (loss)—
 —
 —
 772
 —
 (12) 760
Long-term incentive plan activity207
 10
 —
 —
 —
 —
 10
Employee stock purchase plan issuances317
 19
 —
 —
 —
 —
 19
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 (18) (18)
Common stock dividends
($0.36/common share)		—
 —
 —
 (353) —
 —
 (353)
Other comprehensive income net of income taxes—
 —
 —
 —
 27
 —
 27
Balance, September 30, 2019973,941
 $19,238
 $(123) $15,871
 $(2,963) $2,329
 $34,352

Six Months Ended June 30, 2018Nine Months Ended September 30, 2018
(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, 2017965,168
 $18,964
 $(123) $14,081
 $(3,026) $2,291
 $32,187
965,168
 $18,964
 $(123) $14,081
 $(3,026) $2,291
 $32,187
Net income—
 —
 —
 585
 —
 51
 636
—
 —
 —
 585
 —
 51
 636
Long-term incentive plan activity1,685
 (3) —
 —
 —
 —
 (3)1,685
 (3) —
 —
 —
 —
 (3)
Employee stock purchase plan issuances361
 12
 —
 —
 —
 —
 12
361
 12
 —
 —
 —
 —
 12
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 (9) (9)—
 —
 —
 —
 —
 (9) (9)
Common stock dividends
($0.35/common share)

—
 —
 —
 (334) —
 —
 (334)—
 —
 —
 (334) —
 —
 (334)
Other comprehensive income, net of income taxes—
 —
 —
 —
 71
 1
 72
—
 —
 —
 —
 71
 1
 72
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 —
 —
 14
 (10) —
 4
—
 —
 —
 14
 (10) —
 4
Balance, March 31, 2018967,214
 $18,973
 $(123) $14,346
 $(2,965) $2,334
 $32,565
967,214
 $18,973
 $(123) $14,346
 $(2,965) $2,334
 $32,565
Net income—
 —
 —
 539
 —
 3
 542
—
 —
 —
 539
 —
 3
 542
Long-term incentive plan activity183
 20
 —
 —
 —
 —
 20
183
 20
 —
 —
 —
 —
 20
Employee stock purchase plan issuances342
 15
 —
 —
 —
 —
 15
342
 15
 —
 —
 —
 —
 15
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 (14) (14)—
 —
 —
 —
 —
 (14) (14)
Common stock dividends
($0.35/common share)
—
 —
 —
 (334) —
 —
 (334)—
 —
 —
 (334) —
 —
 (334)
Other comprehensive income, net of income taxes—
 —
 —
 —
 44
 1
 45
—
 —
 —
 —
 44
 1
 45
Balance, June 30, 2018967,739
 $19,008
 $(123) $14,551
 $(2,921) $2,324
 $32,839
967,739
 $19,008
 $(123) $14,551
 $(2,921) $2,324
 $32,839
Net Income—
 —
 —
 733
 —
 67
 800
Long-term incentive plan activity809
 15
 —
 —
 —
 —
 15
Employee stock purchase plan issuances294
 40
 —
 —
 —
 —
 40
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 (23) (23)
Common stock dividends
($0.35/common share)		—
 —
 —
 (335) —
 —
 (335)
Other comprehensive income, net of income taxes—
 —
 —
 —
 52
 —
 52
Balance, September 30, 2018968,842
 $19,063
 $(123) $14,949
 $(2,869) $2,368
 $33,388

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2019 2018 2019 20182019 2018 2019 2018
Operating revenues              
Operating revenues$3,958
 $4,306
 $8,937
 $9,419
$4,499
 $4,970
 $13,436
 $14,389
Operating revenues from affiliates252
 273
 569
 671
275
 308
 844
 979
Total operating revenues4,210

4,579

9,506

10,090
4,774

5,278

14,280

15,368
Operating expenses              
Purchased power and fuel2,289
 2,277
 5,493
 5,566
2,648
 2,977
 8,141
 8,542
Purchased power and fuel from affiliates3
 3
 4
 7
3
 3
 7
 10
Operating and maintenance1,117
 1,247
 2,185
 2,425
947
 1,218
 3,131
 3,643
Operating and maintenance from affiliates149
 171
 299
 331
140
 152
 439
 483
Depreciation and amortization409
 466
 814
 914
407
 468
 1,221
 1,383
Taxes other than income129
 134
 264
 272
129
 143
 394
 414
Total operating expenses4,096

4,298

9,059

9,515
4,274

4,961

13,333

14,475
Gain on sales of assets and businesses33
 1
 33
 54
(Loss) gain on sales of assets and businesses(18) (6) 15
 48
Operating income147

282

480

629
482

311

962

941
Other income and (deductions)              
Interest expense, net(107) (93) (209) (184)(101) (93) (310) (278)
Interest expense to affiliates(9) (9) (18) (18)(8) (8) (26) (27)
Other, net171
 29
 601
 (15)128
 179
 729
 164
Total other income and (deductions)55

(73)
374

(217)19

78

393

(141)
Income before income taxes202
 209
 854
 412
501
 389
 1,355
 800
Income taxes78
 23
 301
 32
87
 78
 388
 110
Equity in losses of unconsolidated affiliates(6) (5) (13) (12)(170) (11) (183) (23)
Net income118

181

540

368
244

300

784

667
Net income attributable to noncontrolling interests10
 3
 68
 54
Net (loss) income attributable to noncontrolling interests(13) 66
 56
 120
Net income attributable to membership interest$108

$178

$472

$314
$257

$234

$728

$547
Comprehensive income, net of income taxes              
Net income$118
 $181
 $540
 $368
$244
 $300
 $784
 $667
Other comprehensive income (loss), net of income taxes              
Unrealized (loss) gain on cash flow hedges(1) 5
 —
 12
Unrealized (loss) gain on investments in unconsolidated affiliates(2) 2
 (4) 3
Unrealized gain (loss) on foreign currency translation2
 (5) 4
 (6)
Other comprehensive (loss) income(1)
2

—

9
Unrealized gain on cash flow hedges—
 —
 —
 12
Unrealized gain on investments in unconsolidated affiliates5
 —
 1
 3
Unrealized (loss) gain on foreign currency translation(2) 2
 2
 (4)
Other comprehensive income3

2

3

11
Comprehensive income117

183

540

377
247

302

787

678
Comprehensive income attributable to noncontrolling interests9
 4
 66
 56
Comprehensive (loss) income attributable to noncontrolling interests(10) 66
 57
 122
Comprehensive income attributable to membership interest$108
 $179
 $474
 $321
$257
 $236
 $730
 $556

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities      
Net income$540
 $368
$784
 $667
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization1,580
 1,735
2,377
 2,608
Impairment of long-lived assets9
 41
Asset impairments174
 49
Gain on sales of assets and businesses(33) (54)(15) (48)
Deferred income taxes and amortization of investment tax credits151
 (149)201
 (278)
Net fair value changes related to derivatives114
 158
102
 73
Net realized and unrealized (gains) losses on NDT funds(404) 80
Net realized and unrealized gains on NDT funds(467) (21)
Other non-cash operating activities(50) 85
(95) 187
Changes in assets and liabilities:
 

 
Accounts receivable472
 258
395
 126
Receivables from and payables to affiliates, net(18) 7
(12) (7)
Inventories32
 34
(36) (10)
Accounts payable and accrued expenses(507) (272)(428) (59)
Option premiums received (paid), net48
 (36)13
 (36)
Collateral (posted) received, net(318) 91
(292) 228
Income taxes321
 58
327
 220
Pension and non-pension postretirement benefit contributions(158) (129)(165) (134)
Other assets and liabilities(351) (212)(390) (154)
Net cash flows provided by operating activities1,428

2,063
2,473

3,411
Cash flows from investing activities      
Capital expenditures(890) (1,298)(1,282) (1,660)
Proceeds from NDT fund sales6,920
 3,822
8,443
 6,379
Investment in NDT funds(6,847) (3,924)(8,437) (6,553)
Acquisition of assets and businesses, net—
 (57)—
 (57)
Proceeds from sales of assets and businesses14
 89
17
 90
Changes in Exelon intercompany money pool(179) (185)
Other investing activities8
 4
(6) (5)
Net cash flows used in investing activities(974)
(1,549)(1,265)
(1,806)
Cash flows from financing activities      
Issuance of long-term debt40
 13
41
 14
Retirement of long-term debt(130) (76)(196) (100)
Changes in Exelon intercompany money pool(100) (54)(100) (54)
Distributions to member(449) (377)(674) (688)
Contributions from member—

54
Other financing activities(21) (24)(37) (46)
Net cash flows used in financing activities(660)
(518)(966)
(820)
Decrease in cash, cash equivalents and restricted cash(206) (4)
Increase in cash, cash equivalents and restricted cash242
 785
Cash, cash equivalents and restricted cash at beginning of period903
 554
903
 554
Cash, cash equivalents and restricted cash at end of period$697

$550
$1,145

$1,339
      
Supplemental cash flow information      
Decrease in capital expenditures not paid$(30) $(310)$(24) $(226)
Increase in PPE related to ARO update301
 47
342
 47

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$575
 $750
$1,019
 $750
Restricted cash and cash equivalents122
 153
126
 153
Accounts receivable, net      
Customer (net of allowance for uncollectible accounts of $96 and $103 as of June 30, 2019 and December 31, 2018, respectively)2,528
 2,941
Other (net of allowance for uncollectible accounts of $1 as of both June 30, 2019 and December 31, 2018)326
 562
Customer (net of allowance for uncollectible accounts of $75 and $103 as of September 30, 2019 and December 31, 2018, respectively)2,587
 2,941
Other (net of allowance for uncollectible accounts of $1 as of both September 30, 2019 and December 31, 2018)337
 562
Mark-to-market derivative assets526
 804
602
 804
Receivables from affiliates159
 173
166
 173
Receivable from Exelon intercompany money pool179
 —
Unamortized energy contract assets47
 49
49
 49
Inventories, net      
Fossil fuel and emission allowances201
 251
243
 251
Materials and supplies984
 963
1,010
 963
Assets held for sale880
 904
18
 904
Other849
 883
1,002
 883
Total current assets7,376

8,433
7,159

8,433
Property, plant and equipment (net of accumulated depreciation and amortization of $12,902 and $12,206 as of June 30, 2019 and December 31, 2018, respectively)23,810
 23,981
Property, plant and equipment (net of accumulated depreciation and amortization of $11,972 and $12,206 as of September 30, 2019 and December 31, 2018, respectively)23,591
 23,981
Deferred debits and other assets      
Nuclear decommissioning trust funds12,513
 11,661
12,706
 11,661
Investments401
 414
248
 414
Goodwill47
 47
47
 47
Mark-to-market derivative assets533
 452
483
 452
Prepaid pension asset1,506
 1,421
1,472
 1,421
Unamortized energy contract assets361
 371
352
 371
Deferred income taxes14
 21
11
 21
Other1,841
 755
1,915
 755
Total deferred debits and other assets17,216

15,142
17,234

15,142
Total assets(a)
$48,402

$47,556
$47,984

$47,556

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND EQUITY      
Current liabilities      
Long-term debt due within one year$2,733
 $906
$2,706
 $906
Accounts payable1,517
 1,847
1,583
 1,847
Accrued expenses767
 898
762
 898
Payables to affiliates122
 139
134
 139
Borrowings from Exelon intercompany money pool—
 100
—
 100
Mark-to-market derivative liabilities134
 449
212
 449
Unamortized energy contract liabilities26
 31
21
 31
Renewable energy credit obligation298
 343
374
 343
Liabilities held for sale764
 777
11
 777
Other481
 279
541
 279
Total current liabilities6,842
 5,769
6,344
 5,769
Long-term debt5,079
 6,989
5,018
 6,989
Long-term debt to affiliates892
 898
889
 898
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits3,534
 3,383
3,607
 3,383
Asset retirement obligations9,792
 9,450
9,855
 9,450
Non-pension postretirement benefit obligations889
 900
885
 900
Spent nuclear fuel obligation1,186
 1,171
1,193
 1,171
Payables to affiliates2,928
 2,606
2,960
 2,606
Mark-to-market derivative liabilities206
 252
163
 252
Unamortized energy contract liabilities13
 20
11
 20
Other1,449
 610
1,466
 610
Total deferred credits and other liabilities19,997
 18,392
20,140
 18,392
Total liabilities(a)
32,810
 32,048
32,391
 32,048
Commitments and contingencies

 


 

Equity      
Member’s equity      
Membership interest9,525
 9,518
9,525
 9,518
Undistributed earnings3,746
 3,724
3,778
 3,724
Accumulated other comprehensive loss, net(36) (38)(36) (38)
Total member’s equity13,235
 13,204
13,267
 13,204
Noncontrolling interests2,357
 2,304
2,326
 2,304
Total equity15,592
 15,508
15,593
 15,508
Total liabilities and equity$48,402
 $47,556
$47,984
 $47,556
__________
(a)Generation’s consolidated assets include $9,503$9,443 million and $9,634 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,513$3,467 million and $3,480 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2 — Variable Interest Entities for additional information.

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
Six Months Ended June 30, 2019Nine Months Ended September 30, 2019
Member’s Equity    Member’s Equity    
(In millions)
Membership
Interest
 
Undistributed
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 Total Equity
Membership
Interest
 
Undistributed
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 Total Equity
Balance, December 31, 2018$9,518
 $3,724
 $(38) $2,304
 $15,508
$9,518
 $3,724
 $(38) $2,304
 $15,508
Net income—
 363
 —
 59
 422
—
 363
 —
 59
 422
Changes in equity of noncontrolling interests—
 —
 —
 (17) (17)—
 —
 —
 (17) (17)
Sale of noncontrolling interests7
 —
 —
 —
 7
7
 —
 —
 —
 7
Distributions to member—
 (225) —
 —
 (225)—
 (225) —
 —
 (225)
Other comprehensive income (loss), net of income taxes—
 —
 2
 (1) 1
—
 —
 2
 (1) 1
Balance, March 31, 2019$9,525

$3,862

$(36)
$2,345

$15,696
$9,525

$3,862

$(36)
$2,345

$15,696
Net income—
 108
 —
 10
 118
—
 108
 —
 10
 118
Changes in equity of noncontrolling interests—
 —
 —
 3
 3
—
 —
 —
 3
 3
Distributions to member—
 (224) —
 —
 (224)—
 (224) —
 —
 (224)
Other comprehensive loss, net of income taxes—
 —
 —
 (1) (1)—
 —
 —
 (1) (1)
Balance, June 30, 2019$9,525
 $3,746
 $(36) $2,357
 $15,592
$9,525
 $3,746
 $(36) $2,357
 $15,592
Net income (loss)—
 257
 —
 (13) 244
Changes in equity of noncontrolling interests—
 —
 —
 (18) (18)
Distributions to member—
 (225) —
 —
 (225)
Balance, September 30, 2019$9,525
 $3,778
 $(36) $2,326
 $15,593


Six Months Ended June 30, 2018Nine Months Ended September 30, 2018
Member’s Equity    Member’s Equity    
(In millions)
Membership
Interest
 
Undistributed
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 Total Equity
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
$9,357
 $4,349
 $(37) $2,290
 $15,959
Net income—
 136
 —
 50
 186
—
 136
 —
 50
 186
Changes in equity of noncontrolling interests—
 —
 —
 (9) (9)—
 —
 —
 (9) (9)
Distributions to member—
 (188) —
 —
 (188)—
 (188) —
 —
 (188)
Other comprehensive income, net of income taxes—
 —
 6
 1
 7
—
 —
 6
 1
 7
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 6
 (3) —
 3
—
 6
 (3) —
 3
Balance, March 31, 2018$9,357
 $4,303
 $(34) $2,332
 $15,958
$9,357
 $4,303
 $(34) $2,332
 $15,958
Net income—
 178
 —
 3
 181
—
 178
 —
 3
 181
Changes in equity of noncontrolling interests—
 —
 —
 (13) (13)—
 —
 —
 (13) (13)
Distributions to member—
 (189) —
 —
 (189)—
 (189) —
 —
 (189)
Other comprehensive income, net of income taxes—
 —
 1
 1
 2
—
 —
 1
 1
 2
Balance, June 30, 2018$9,357
 $4,292
 $(33) $2,323
 $15,939
$9,357
 $4,292
 $(33) $2,323
 $15,939
Net income—
 234
 —
 66
 300
Changes in equity of noncontrolling interests—
 —
 —
 (23) (23)
Contribution from member54
 —
 —
 —
 54
Distributions to member—
 (312) —
 —
 (312)
Other comprehensive income, net of income taxes—
 —
 2
 —
 2
Balance, September 30, 2018$9,411
 $4,214
 $(31) $2,366
 $15,960


COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2019 2018 2019 20182019 2018 2019 2018
Operating revenues              
Electric operating revenues$1,360
 $1,410
 $2,792
 $2,903
$1,635
 $1,609
 $4,427
 $4,512
Revenues from alternative revenue programs(14) (17) (42) (12)(56) (15) (98) (27)
Operating revenues from affiliates5
 5
 9
 19
4
 4
 13
 23
Total operating revenues1,351

1,398

2,759

2,910
1,583

1,598

4,342

4,508
Operating expenses              
Purchased power316
 373
 705
 784
494
 496
 1,199
 1,281
Purchased power from affiliate91
 104
 187
 298
83
 123
 270
 421
Operating and maintenance245
 255
 504
 509
267
 276
 771
 785
Operating and maintenance from affiliate60
 69
 122
 129
73
 61
 196
 189
Depreciation and amortization257
 231
 508
 459
259
 237
 767
 696
Taxes other than income71
 79
 148
 156
80
 82
 228
 238
Total operating expenses1,040

1,111

2,174

2,335
1,256

1,275

3,431

3,610
Gain on sales of assets—
 1
 3
 5
1
 —
 4
 5
Operating income311

288

588

580
328

323

915

903
Other income and (deductions)              
Interest expense, net(86) (82) (171) (168)(87) (82) (258) (251)
Interest expense to affiliates(3) (3) (7) (7)(4) (3) (10) (10)
Other, net10
 4
 19
 12
8
 7
 27
 21
Total other income and (deductions)(79)
(81)
(159)
(163)(83)
(78)
(241)
(240)
Income before income taxes232
 207
 429
 417
245
 245
 674
 663
Income taxes46
 43
 85
 88
45
 52
 130
 140
Net income$186

$164

$344

$329
$200

$193

$544

$523
Comprehensive income$186
 $164
 $344
 $329
$200
 $193
 $544
 $523

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities      
Net income$344
 $329
$544
 $523
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization508
 459
767
 696
Deferred income taxes and amortization of investment tax credits64
 84
115
 214
Other non-cash operating activities87
 117
180
 187
Changes in assets and liabilities:      
Accounts receivable56
 (133)(38) (190)
Receivables from and payables to affiliates, net(16) 15
(27) 8
Inventories(5) 5
(16) 4
Accounts payable and accrued expenses(121) (41)(132) (38)
Collateral posted, net11
 (13)43
 (10)
Income taxes43
 (15)25
 (65)
Pension and non-pension postretirement benefit contributions(68) (39)(71) (41)
Other assets and liabilities(236) (166)(245) (170)
Net cash flows provided by operating activities667

602
1,145

1,118
Cash flows from investing activities      
Capital expenditures(961) (1,026)(1,413) (1,540)
Other investing activities17
 17
25
 22
Net cash flows used in investing activities(944)
(1,009)(1,388)
(1,518)
Cash flows from financing activities      
Changes in short-term borrowings303
 320
387
 —
Issuance of long-term debt400
 800
400
 1,350
Retirement of long-term debt(300) (700)(300) (840)
Contributions from parent124
 225
187
 387
Dividends paid on common stock(254) (229)(380) (345)
Other financing activities(10) (10)(10) (16)
Net cash flows provided by financing activities263

406
284

536
Decrease in cash, cash equivalents and restricted cash(14) (1)
Increase in cash, cash equivalents and restricted cash41
 136
Cash, cash equivalents and restricted cash at beginning of period330
 144
330
 144
Cash, cash equivalents and restricted cash at end of period$316

$143
$371

$280
      
Supplemental cash flow information      
Decrease in capital expenditures not paid$(77) $(22)$(52) $(28)

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$65
 $135
$76
 $135
Restricted cash77
 29
124
 29
Accounts receivable, net      
Customer (net of allowance for uncollectible accounts of $59 and $61 as of June 30, 2019 and December 31, 2018, respectively)528
 539
Other (net of allowance for uncollectible accounts of $18 and $20 as of June 30, 2019 and December 31, 2018, respectively)268
 320
Customer (net of allowance for uncollectible accounts of $65 and $61 as of September 30, 2019 and December 31, 2018, respectively)561
 539
Other (net of allowance for uncollectible accounts of $21 and $20 as of September 30, 2019 and December 31, 2018, respectively)322
 320
Receivables from affiliates20
 20
27
 20
Inventories, net151
 148
162
 148
Regulatory assets297
 293
286
 293
Other76
 86
48
 86
Total current assets1,482

1,570
1,606

1,570
Property, plant and equipment (net of accumulated depreciation and amortization of $4,949 and $4,684 as of June 30, 2019 and December 31, 2018, respectively)22,527
 22,058
Property, plant and equipment (net of accumulated depreciation and amortization of $5,046 and $4,684 as of September 30, 2019 and December 31, 2018, respectively)22,795
 22,058
Deferred debits and other assets      
Regulatory assets1,391
 1,307
1,436
 1,307
Investments6
 6
6
 6
Goodwill2,625
 2,625
2,625
 2,625
Receivables from affiliates2,458
 2,217
2,487
 2,217
Prepaid pension asset1,046
 1,035
1,020
 1,035
Other354
 395
351
 395
Total deferred debits and other assets7,880

7,585
7,925

7,585
Total assets$31,889

$31,213
$32,326

$31,213

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY      
Current liabilities      
Short-term borrowings$303
 $—
$387
 $—
Long-term debt due within one year—
 300
500
 300
Accounts payable478
 607
520
 607
Accrued expenses305
 373
275
 373
Payables to affiliates91
 119
87
 119
Customer deposits114
 111
116
 111
Regulatory liabilities186
 293
193
 293
Mark-to-market derivative liability29
 26
27
 26
Other126
 96
138
 96
Total current liabilities1,632
 1,925
2,243
 1,925
Long-term debt8,195
 7,801
7,696
 7,801
Long-term debt to financing trust205
 205
205
 205
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits3,929
 3,813
4,016
 3,813
Asset retirement obligations119
 118
120
 118
Non-pension postretirement benefits obligations191
 201
185
 201
Regulatory liabilities6,322
 6,050
6,390
 6,050
Mark-to-market derivative liability244
 223
253
 223
Other592
 630
621
 630
Total deferred credits and other liabilities11,397
 11,035
11,585
 11,035
Total liabilities21,429
 20,966
21,729
 20,966
Commitments and contingencies

 


 

Shareholders’ equity      
Common stock1,588
 1,588
1,588
 1,588
Other paid-in capital7,446
 7,322
7,509
 7,322
Retained deficit unappropriated(1,639) (1,639)(1,639) (1,639)
Retained earnings appropriated3,065
 2,976
3,139
 2,976
Total shareholders’ equity10,460
 10,247
10,597
 10,247
Total liabilities and shareholders’ equity$31,889
 $31,213
$32,326
 $31,213

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Six Months Ended June 30, 2019Nine Months Ended September 30, 2019
(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, 2018$1,588
 $7,322
 $(1,639) $2,976
 $10,247
$1,588
 $7,322
 $(1,639) $2,976
 $10,247
Net income—
 —
 157
 —
 157
—
 —
 157
 —
 157
Appropriation of retained earnings for future dividends—
 —
 (157) 157
 —
—
 —
 (157) 157
 —
Common stock dividends—
 —
 —
 (127) (127)—
 —
 —
 (127) (127)
Contributions from parent—
 63
 —
 —
 63
—
 63
 —
 —
 63
Balance, March 31, 20191,588
 7,385
 (1,639) 3,006
 10,340
$1,588
 $7,385
 $(1,639) $3,006
 $10,340
Net income—
 —
 186
 —
 186
—
 —
 186
 —
 186
Appropriation of retained earnings for future dividends—
 —
 (186) 186
 —
—
 —
 (186) 186
 —
Common stock dividends—
 —
 —
 (127) (127)—
 —
 —
 (127) (127)
Contributions from parent—
 61
 —
 —
 61
—
 61
 —
 —
 61
Balance, June 30, 2019$1,588
 $7,446
 $(1,639) $3,065
 $10,460
$1,588
 $7,446
 $(1,639) $3,065
 $10,460
         
Net income—
 —
 200
 —
 200
Appropriation of retained earnings for future dividends—
 —
 (200) 200
 —
Common stock dividends—
 —
 —
 (126) (126)
Contributions from parent—
 63
 —
 —
 63
Balance, September 30, 2019$1,588
 $7,509
 $(1,639) $3,139
 $10,597
                  
Six Months Ended June 30, 2018Nine Months Ended September 30, 2018
(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, 2017$1,588
 $6,822
 $(1,639) $2,771
 $9,542
$1,588
 $6,822
 $(1,639) $2,771
 $9,542
Net income—
 —
 165
 —
 165
—
 —
 165
 —
 165
Appropriation of retained earnings for future dividends—
 —
 (165) 165
 —
—
 —
 (165) 165
 —
Common stock dividends—
 —
 —
 (114) (114)—
 —
 —
 (114) (114)
Contributions from parent—
 113
 —
 —
 113
—
 113
 —
 —
 113
Balance, March 31, 20181,588
 6,935
 (1,639) 2,822
 9,706
$1,588
 $6,935
 $(1,639) $2,822
 $9,706
Net income—
 —
 164
 —
 164
—
 —
 164
 —
 164
Appropriation of retained earnings for future dividends—
 —
 (164) 164
 —
—
 —
 (164) 164
 —
Common stock dividends—
 —
 —
 (115) (115)—
 —
 —
 (115) (115)
Contributions from parent—
 112
 —
 —
 112
—
 112
 —
 —
 112
Balance, June 30, 2018$1,588
 $7,047
 $(1,639) $2,871
 $9,867
$1,588
 $7,047
 $(1,639) $2,871
 $9,867
Net income—
 —
 193
 —
 193
Appropriation of retained earnings for future dividends—
 —
 (193) 193
 —
Common stock dividends—
 —
 —
 (115) (115)
Contributions from parent—
 162
 —
 —
 162
Balance, September 30, 2018$1,588
 $7,209
 $(1,639) $2,949
 $10,107

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2019 2018 2019 20182019 2018 2019 2018
Operating revenues              
Electric operating revenues$567
 $556
 $1,188
 $1,189
$726
 $697
 $1,914
 $1,886
Natural gas operating revenues89
 93
 369
 325
62
 57
 431
 382
Revenues from alternative revenue programs(3) 2
 (6) 1
(11) 1
 (16) 2
Operating revenues from affiliates2
 2
 3
 3
1
 2
 4
 5
Total operating revenues655

653

1,554

1,518
778

757

2,333

2,275
Operating expenses              
Purchased power124
 161
 275
 361
185
 215
 461
 576
Purchased fuel32
 37
 166
 134
18
 14
 184
 148
Purchased power from affiliate35
 24
 79
 60
43
 34
 122
 94
Operating and maintenance162
 153
 349
 387
182
 184
 531
 572
Operating and maintenance from affiliates37
 38
 75
 79
37
 35
 112
 114
Depreciation and amortization83
 74
 164
 149
83
 75
 247
 224
Taxes other than income37
 39
 79
 79
47
 46
 126
 125
Total operating expenses510

526

1,187

1,249
595

603

1,783

1,853
Gain on sales of assets—
 —
 —
 1
Operating income145

127

367

269
183

154

550

423
Other income and (deductions)              
Interest expense, net(30) (28) (61) (57)(30) (28) (91) (85)
Interest expense to affiliates(3) (4) (6) (7)(3) (4) (9) (11)
Other, net3
 —
 7
 2
4
 2
 11
 4
Total other income and (deductions)(30)
(32)
(60)
(62)(29)
(30)
(89)
(92)
Income before income taxes115
 95
 307

207
154
 124
 461

331
Income taxes13
 (1) 37
 (3)14
 (2) 51
 (5)
Net income$102

$96

$270

$210
$140

$126

$410

$336
Comprehensive income$102
 $96
 $270
 $210
$140
 $126
 $410
 $336

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities      
Net income$270
 $210
$410
 $336
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization164
 149
247
 224
Gain on sales of assets—
 (1)
Deferred income taxes and amortization of investment tax credits8
 (10)6
 5
Other non-cash operating activities15
 22
28
 41
Changes in assets and liabilities:      
Accounts receivable39
 (43)46
 (85)
Receivables from and payables to affiliates, net(4) (4)(12) 1
Inventories12
 4
(3) (13)
Accounts payable and accrued expenses(31) (18)(32) (1)
Income taxes(11) 19
(15) (16)
Pension and non-pension postretirement benefit contributions(27) (25)(26) (25)
Other assets and liabilities(117) (50)(111) 26
Net cash flows provided by operating activities318

254
538

492
Cash flows from investing activities      
Capital expenditures(447) (411)(675) (615)
Other investing activities4
 5
7
 6
Net cash flows used in investing activities(443)
(406)(668)
(609)
Cash flows from financing activities      
Changes in short-term borrowings—
 50
Issuance of long-term debt—
 375
325
 700
Retirement of long-term debt—
 (500)—
 (500)
Changes in Exelon intercompany money pool52
 233
Contributions from parent145
 41
174
 71
Dividends paid on common stock(180) (293)(268) (300)
Other financing activities(1) (6)(6) (22)
Net cash flows provided by (used in) financing activities16

(100)225

(51)
Decrease in cash, cash equivalents and restricted cash(109) (252)
Increase (decrease) in cash, cash equivalents and restricted cash95
 (168)
Cash, cash equivalents and restricted cash at beginning of period135
 275
135
 275
Cash, cash equivalents and restricted cash at end of period$26

$23
$230

$107
      
Supplemental cash flow information      
Increase (decrease) in capital expenditures not paid$33
 $(17)
Increase in capital expenditures not paid$42
 $4

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$20
 $130
$224
 $130
Restricted cash and cash equivalents6
 5
6
 5
Accounts receivable, net      
Customer (net of allowance for uncollectible accounts of $53 and $53 as of June 30, 2019 and December 31, 2018, respectively)302
 321
Other (net of allowance for uncollectible accounts of $6 and $8 as of June 30, 2019 and December 31, 2018, respectively)123
 151
Customer (net of allowance for uncollectible accounts of $54 and $53 as of September 30, 2019 and December 31, 2018, respectively)286
 321
Other (net of allowance for uncollectible accounts of $7 and $8 as of September 30, 2019 and December 31, 2018, respectively)118
 151
Receivable from affiliates7
 —
Inventories, net      
Fossil fuel26
 38
41
 38
Materials and supplies37
 37
37
 37
Prepaid utility taxes69
 —
34
 —
Regulatory assets52
 81
63
 81
Other23
 19
27
 19
Total current assets658

782
843

782
Property, plant and equipment (net of accumulated depreciation and amortization of $3,636 and $3,561 as of June 30, 2019 and December 31, 2018, respectively)8,940
 8,610
Property, plant and equipment (net of accumulated depreciation and amortization of $3,670 and $3,561 as of September 30, 2019 and December 31, 2018, respectively)9,100
 8,610
Deferred debits and other assets      
Regulatory assets508
 460
540
 460
Investments25
 25
26
 25
Receivable from affiliates470
 389
473
 389
Prepaid pension asset371
 349
367
 349
Other30
 27
30
 27
Total deferred debits and other assets1,404

1,250
1,436

1,250
Total assets$11,002

$10,642
$11,379

$10,642

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Accounts payable375
 370
382
 370
Accrued expenses102
 113
97
 113
Payables to affiliates55
 59
54
 59
Borrowings from Exelon intercompany money pool52
 —
Customer deposits69
 68
69
 68
Regulatory liabilities91
 175
93
 175
Other40
 24
27
 24
Total current liabilities784
 809
722
 809
Long-term debt3,085
 3,084
3,404
 3,084
Long-term debt to financing trusts184
 184
184
 184
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits1,999
 1,933
2,034
 1,933
Asset retirement obligations27
 27
28
 27
Non-pension postretirement benefits obligations289
 288
289
 288
Regulatory liabilities500
 421
503
 421
Other79
 76
79
 76
Total deferred credits and other liabilities2,894
 2,745
2,933
 2,745
Total liabilities6,947
 6,822
7,243
 6,822
Commitments and contingencies

 


 

Shareholder’s equity      
Common stock2,723
 2,578
2,752
 2,578
Retained earnings1,332
 1,242
1,384
 1,242
Total shareholder’s equity4,055
 3,820
4,136
 3,820
Total liabilities and shareholder's equity$11,002
 $10,642
$11,379
 $10,642

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
Six months ended June 30, 2019Nine months ended September 30, 2019
(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, 2018$2,578
 $1,242
 $—
 $3,820
$2,578
 $1,242
 $—
 $3,820
Net income—
 168
 —
 168
—
 168
 —
 168
Common stock dividends—
 (90) —
 (90)—
 (90) —
 (90)
Contributions from parent145
 —
 —
 145
145
 —
 —
 145
Balance, March 31, 20192,723
 1,320
 —
 4,043
$2,723
 $1,320
 $—
 $4,043
Net income—
 102
 $—
 102
—
 102
 —
 102
Common stock dividends—
 (90) —
 (90)—
 (90) —
 (90)
Balance, June 30, 20192,723
 1,332
 —
 4,055
$2,723
 $1,332
 $—
 $4,055
       
Net income—
 140
 —
 140
Common stock dividends—
 (88) —
 (88)
Contributions from parent29
 —
 —
 29
Balance, September 30, 2019$2,752
 $1,384
 $—
 $4,136
              
Six months ended June 30, 2018Nine months ended September 30, 2018
(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, 2017$2,489
 $1,087
 $1
 $3,577
$2,489
 $1,087
 $1
 $3,577
Net income—
 113
 —
 113
—
 113
 —
 113
Common stock dividends—
 (287) —
 (287)—
 (287) —
 (287)
Impact of adoption of Recognition and Measurement of Financial Assets and
Liabilities Standard
—
 1
 (1) —
—
 1
 (1) —
Balance, March 31, 20182,489
 914
 —
 3,403
$2,489
 $914
 $—
 $3,403
Net income—
 96
 $—
 96
—
 96
 —
 96
Common stock dividends—
 (5) $—
 (5)—
 (5) —
 (5)
Contributions from parent41
 —
 $—
 41
41
 —
 —
 41
Balance, June 30, 2018$2,530
 $1,005
 $—
 $3,535
$2,530
 $1,005
 $—
 $3,535
Net income—
 126
 —
 126
Common stock dividends—
 (7) —
 (7)
Contributions from parent30
 —
 —
 30
Balance, September 30, 2018$2,560
 $1,124
 $—
 $3,684

BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2019 2018 2019 20182019 2018 2019 2018
Operating revenues              
Electric operating revenues$540
 $542
 $1,191
 $1,196
$623
 $652
 $1,814
 $1,847
Natural gas operating revenues97
 118
 405
 448
79
 79
 484
 527
Revenues from alternative revenue programs6
 (4) 17
 (17)(5) (6) 11
 (23)
Operating revenues from affiliates6
 6
 12
 12
6
 6
 18
 18
Total operating revenues649

662

1,625

1,639
703

731

2,327

2,369
Operating expenses              
Purchased power131
 135
 322
 327
159
 183
 480
 510
Purchased fuel21
 32
 116
 155
12
 21
 128
 176
Purchased power from affiliate56
 62
 132
 127
64
 68
 196
 195
Operating and maintenance142
 135
 294
 318
157
 144
 451
 462
Operating and maintenance from affiliates40
 41
 78
 79
39
 38
 118
 116
Depreciation and amortization117
 114
 252
 248
116
 110
 368
 358
Taxes other than income62
 59
 131
 124
65
 64
 195
 188
Total operating expenses569

578

1,325

1,378
612

628

1,936

2,005
Gain on sales of assets—
 1
 —
 1
—
 —
 —
 1
Operating income80

85

300

262
91

103

391

365
Other income and (deductions)              
Interest expense, net(29) (25) (58) (51)(31) (27) (89) (78)
Other, net5
 4
 11
 9
7
 5
 18
 14
Total other income and (deductions)(24)
(21)
(47)
(42)(24)
(22)
(71)
(64)
Income before income taxes56
 64
 253

220
67
 81
 320

301
Income taxes11
 13
 47
 41
12
 18
 59
 59
Net income$45

$51

$206

$179
$55

$63

$261

$242
Comprehensive income$45
 $51
 $206
 $179
$55
 $63
 $261
 $242

BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities      
Net income$206
 $179
$261
 $242
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization252
 248
368
 358
Deferred income taxes and amortization of investment tax credits47
 39
66
 82
Other non-cash operating activities41
 27
63
 42
Changes in assets and liabilities:      
Accounts receivable85
 73
110
 72
Receivables from and payables to affiliates, net(14) (4)(14) (4)
Inventories5
 5
(5) (8)
Accounts payable and accrued expenses(73) (48)(28) (3)
Collateral posted, net(5) —
Collateral (posted) received, net(5) 1
Income taxes(29) (45)(43) (48)
Pension and non-pension postretirement benefit contributions(42) (49)(45) (50)
Other assets and liabilities(21) 39
(65) (9)
Net cash flows provided by operating activities452

464
663

675
Cash flows from investing activities      
Capital expenditures(542) (434)(842) (667)
Other investing activities4
 6
4
 8
Net cash flows used in investing activities(538)
(428)(838)
(659)
Cash flows from financing activities      
Changes in short-term borrowings194
 59
(35) (77)
Issuance of long-term debt400
 300
Dividends paid on common stock(112) (105)(169) (157)
Net cash flows provided by (used in) financing activities82

(46)
Decrease in cash, cash equivalents and restricted cash(4) (10)
Contributions from parent104
 18
Other financing activities(7) (2)
Net cash flows provided by financing activities293

82
Increase in cash, cash equivalents and restricted cash118
 98
Cash, cash equivalents and restricted cash at beginning of period13
 18
13
 18
Cash, cash equivalents and restricted cash at end of period$9

$8
$131

$116
      
Supplemental cash flow information      
Increase in capital expenditures not paid$24
 $10
$6
 $44

BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$8
 $7
$130
 $7
Restricted cash and cash equivalents1
 6
1
 6
Accounts receivable, net      
Customer (net of allowance for uncollectible accounts of $14 and $16 as of June 30, 2019 and December 31, 2018, respectively)278
 353
Other (net of allowance for uncollectible accounts of $4 as of both June 30, 2019 and December 31, 2018)86
 90
Customer (net of allowance for uncollectible accounts of $13 and $16 as of September 30, 2019 and December 31, 2018, respectively)242
 353
Other (net of allowance for uncollectible accounts of $4 as of both September 30, 2019 and December 31, 2018)110
 90
Receivables from affiliates—
 1
1
 1
Inventories, net      
Fossil fuel26
 36
34
 36
Materials and supplies44
 39
46
 39
Prepaid utility taxes—
 74
—
 74
Regulatory assets164
 177
180
 177
Other7
 3
7
 3
Total current assets614

786
751

786
Property, plant and equipment (net of accumulated depreciation and amortization of $3,720 and $3,633 as of June 30, 2019 and December 31, 2018, respectively)8,612
 8,243
Property, plant and equipment (net of accumulated depreciation and amortization of $3,772 and $3,633 as of September 30, 2019 and December 31, 2018, respectively)8,796
 8,243
Deferred debits and other assets      
Regulatory assets390
 398
386
 398
Investments6
 5
7
 5
Prepaid pension asset289
 279
276
 279
Other95
 5
88
 5
Total deferred debits and other assets780

687
757

687
Total assets$10,006

$9,716
$10,304

$9,716

BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Short-term borrowings$229
 $35
$—
 $35
Accounts payable279
 295
245
 295
Accrued expenses103
 155
165
 155
Payables to affiliates50
 65
51
 65
Customer deposits120
 120
120
 120
Regulatory liabilities36
 77
21
 77
Other51
 27
63
 27
Total current liabilities868
 774
665
 774
Long-term debt2,877
 2,876
3,270
 2,876
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits1,301
 1,222
1,329
 1,222
Asset retirement obligations24
 24
22
 24
Non-pension postretirement benefits obligations198
 201
198
 201
Regulatory liabilities1,162
 1,192
1,158
 1,192
Other128
 73
112
 73
Total deferred credits and other liabilities2,813
 2,712
2,819
 2,712
Total liabilities6,558
 6,362
6,754
 6,362
Commitments and contingencies

 


 

Shareholder's equity      
Common stock1,714
 1,714
1,818
 1,714
Retained earnings1,734
 1,640
1,732
 1,640
Total shareholder's equity3,448
 3,354
3,550
 3,354
Total liabilities and shareholder's equity$10,006
 $9,716
$10,304
 $9,716



BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Six Months Ended June 30, 2019Nine Months Ended September 30, 2019
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholder's
Equity
Common
Stock
 
Retained
Earnings
 
Total
Shareholder's
Equity
Balance, December 31, 2018$1,714
 $1,640
 $3,354
$1,714
 $1,640
 $3,354
Net income—
 160
 160
—
 160
 160
Common stock dividends—
 (56) (56)—
 (56) (56)
Balance, March 31, 2019$1,714
 $1,744
 $3,458
$1,714
 $1,744
 $3,458
Net income—
 45
 45
—
 45
 45
Common stock dividends—
 (55) (55)—
 (55) (55)
Balance, June 30, 2019$1,714

$1,734
 $3,448
$1,714
 $1,734
 $3,448
Net income—
 55
 55
Contributions from parent104
 —
 104
Common stock dividends—
 (57) (57)
Balance, September 30, 2019$1,818

$1,732
 $3,550
          
Six Months Ended June 30, 2018Nine Months Ended September 30, 2018
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholder's
Equity
Common
Stock
 
Retained
Earnings
 
Total
Shareholder's
Equity
Balance, December 31, 2017$1,605
 $1,536
 $3,141
$1,605
 $1,536
 $3,141
Net income—
 128
 128
—
 128
 128
Common stock dividends—
 (52) (52)—
 (52) (52)
Balance, March 31, 2018$1,605
 $1,612
 $3,217
$1,605
 $1,612
 $3,217
Net income—
 51
 51
—
 51
 51
Common stock dividends—
 (53) (53)—
 (53) (53)
Balance, June 30, 2018$1,605
 $1,610
 $3,215
$1,605
 $1,610
 $3,215
Net income—
 63
 63
Contributions from parent18
 —
 18
Common stock dividends—
 (52) (52)
Balance, September 30, 2018$1,623
 $1,621
 $3,244

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2019 2018 2019 20182019 2018 2019 2018
Operating revenues              
Electric operating revenues$1,067
 $1,052
 $2,205
 $2,202
$1,365
 $1,340
 $3,570
 $3,541
Natural gas operating revenues24
 28
 95
 106
20
 23
 115
 129
Revenues from alternative revenue programs(3) (7) 12
 12
(9) (5) 4
 7
Operating revenues from affiliates3
 3
 7
 7
4
 3
 11
 11
Total operating revenues1,091
 1,076
 2,319
 2,327
1,380
 1,361
 3,700
 3,688
Operating expenses              
Purchased power303
 288
 658
 662
428
 415
 1,086
 1,077
Purchased fuel9
 12
 43
 53
8
 12
 51
 65
Purchased power and fuel from affiliates70
 81
 171
 186
83
 82
 254
 268
Operating and maintenance213
 218
 452
 489
254
 261
 706
 751
Operating and maintenance from affiliates35
 37
 68
 74
36
 31
 105
 106
Depreciation and amortization188
 180
 369
 363
193
 192
 562
 555
Taxes other than income108
 107
 220
 221
122
 123
 342
 343
Total operating expenses926
 923
 1,981
 2,048
1,124
 1,116
 3,106
 3,165
Operating income165
 153

338
 279
256
 245

594
 523
Other income and (deductions)              
Interest expense, net(67) (65) (131) (128)(66) (65) (197) (193)
Other, net14
 11
 27
 22
13
 11
 39
 33
Total other income and (deductions)(53) (54) (104) (106)(53) (54) (158) (160)
Income before income taxes112
 99
 234
 173
203
 191
 436
 363
Income taxes6
 15
 11
 24
14
 4
 25
 28
Equity in earnings of unconsolidated affiliate—
 —
 1
 1
Net income$106
 $84
 $223
 $149
$189
 $187
 $412
 $336
Comprehensive income$106
 $84
 $223
 $149
$189
 $187
 $412
 $336

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities  
  
Net income$223
 $149
$412
 $336
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization369
 363
562
 555
Deferred income taxes and amortization of investment tax credits2
 14
8
 50
Other non-cash operating activities54
 71
122
 109
Changes in assets and liabilities:      
Accounts receivable(34) (28)(64) (89)
Receivables from and payables to affiliates, net(8) 4
1
 10
Inventories(25) 8
(36) —
Accounts payable and accrued expenses(25) 66
—
 115
Income taxes(12) 13
(11) (31)
Pension and non-pension postretirement benefit contributions(11) (62)(15) (66)
Other assets and liabilities(114) (111)(102) (144)
Net cash flows provided by operating activities419
 487
877
 845
Cash flows from investing activities      
Capital expenditures(698) (629)(1,006) (988)
Other investing activities2
 2
3
 2
Net cash flows used in investing activities(696)
(627)(1,003)
(986)
Cash flows from financing activities      
Changes in short-term borrowings(27) (228)78
 (141)
Proceeds from short-term borrowings with maturities greater than 90 days—
 125
—
 125
Repayments of short-term borrowings with maturities greater than 90 days(125) —
(125) —
Issuance of long-term debt410
 300
410
 300
Retirement of long-term debt(125) (25)(130) (33)
Change in Exelon intercompany money pool10
 10
Distributions to member(216) (109)(429) (232)
Contributions from member283
 235
283
 237
Change in Exelon intercompany money pool3
 7
Other financing activities(4) (7)(5) (6)
Net cash flows provided by financing activities199
 298
92
 260
(Decrease) increase in cash, cash equivalents and restricted cash(78) 158
(34) 119
Cash, cash equivalents and restricted cash at beginning of period186
 95
186
 95
Cash, cash equivalents and restricted cash at end of period$108
 $253
$152
 $214
      
Supplemental cash flow information      
(Decrease) increase in capital expenditures not paid$(74) $61
$(62) $54

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$54
 $124
$99
 $124
Restricted cash and cash equivalents37
 43
38
 43
Accounts receivable, net      
Customer (net of allowance for uncollectible accounts of $35 and $50 as of June 30, 2019 and December 31, 2018, respectively)489
 453
Other (net of allowance for uncollectible accounts of $11 and $3 as of June 30, 2019 and December 31, 2018, respectively)196
 177
Customer (net of allowance for uncollectible accounts of $41 and $50 as of September 30, 2019 and December 31, 2018, respectively)512
 453
Other (net of allowance for uncollectible accounts of $16 and $3 as of September 30, 2019 and December 31, 2018, respectively)189
 177
Inventories, net      
Fossil Fuel5
 9
8
 9
Materials and supplies195
 163
203
 163
Regulatory assets496
 489
479
 489
Other74
 75
50
 75
Total current assets1,546

1,533
1,578

1,533
Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,032 and $841 as of June 30, 2019 and December 31, 2018, respectively)13,788
 13,446
Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,124 and $841 as of September 30, 2019 and December 31, 2018, respectively)13,968
 13,446
Deferred debits and other assets      
Regulatory assets2,163
 2,312
2,095
 2,312
Investments133
 130
135
 130
Goodwill4,005
 4,005
4,005
 4,005
Prepaid pension asset446
 486
426
 486
Deferred income taxes13
 12
13
 12
Other360
 60
356
 60
Total deferred debits and other assets7,120

7,005
7,030

7,005
Total assets(a)
$22,454

$21,984
$22,576

$21,984

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND MEMBER'S EQUITY      
Current liabilities      
Short-term borrowings$27
 $179
$132
 $179
Long-term debt due within one year118
 125
118
 125
Accounts payable426
 496
416
 496
Accrued expenses224
 256
279
 256
Payables to affiliates86
 94
95
 94
Borrowings from Exelon intercompany money pool10
 —
Customer deposits117
 116
118
 116
Regulatory liabilities75
 84
78
 84
Unamortized energy contract liabilities119
 119
117
 119
Borrowings from Exelon intercompany money pool3
 —
Other133
 123
152
 123
Total current liabilities1,328
 1,592
1,515
 1,592
Long-term debt6,391
 6,134
6,376
 6,134
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits2,219
 2,146
2,289
 2,146
Asset retirement obligations53
 52
57
 52
Non-pension postretirement benefit obligations100
 103
99
 103
Regulatory liabilities1,789
 1,864
1,725
 1,864
Unamortized energy contract liabilities385
 442
357
 442
Other617
 369
610
 369
Total deferred credits and other liabilities5,163
 4,976
5,137
 4,976
Total liabilities(a)
12,882
 12,702
13,028
 12,702
Commitments and contingencies

 


 

Member's equity      
Membership interest9,503
 9,220
9,503
 9,220
Undistributed earnings69
 62
45
 62
Total member's equity9,572

9,282
9,548

9,282
Total liabilities and member's equity$22,454

$21,984
$22,576

$21,984
__________
(a)PHI’s consolidated total assets include $23$22 million and $33 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $55$50 million and $69 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 — Variable Interest Entities for additional information.

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
 Six Months Ended June 30, 2019
(In millions)Membership Interest Undistributed Earnings (Losses) Member's Equity
Balance, December 31, 2018$9,220
 $62
 $9,282
Net income—
 117
 117
Distributions to member—
 (128) (128)
Contributions from member19
 —
 19
Balance, March 31, 2019$9,239
 $51
 $9,290
Net income—
 106
 106
Distributions to member—
 (88) (88)
Contributions from member264
 —
 264
Balance, June 30, 2019$9,503
 $69
 $9,572

 Nine Months Ended September 30, 2019
(In millions)Membership Interest Undistributed Earnings (Losses) Member's Equity
Balance, December 31, 2018$9,220
 $62
 $9,282
Net income—
 117
 117
Distributions to member—
 (128) (128)
Contributions from member19
 —
 19
Balance, March 31, 2019$9,239
 $51
 $9,290
Net income—

106
 106
Distributions to member—

(88) (88)
Contributions from member264

—
 264
Balance, June 30, 2019$9,503
 $69
 $9,572
Net income—

189
 189
Distributions to member—

(213) (213)
Balance, September 30, 2019$9,503
 $45
 $9,548
 Six Months Ended June 30, 2018
(In millions)Membership Interest Undistributed Earnings (Losses) Member's Equity
Balance, December 31, 2017$8,835
 $(10) $8,825
Net income—
 65
 65
Distributions to member—
 (71) (71)
Balance, March 31, 2018$8,835
 $(16) $8,819
Net income—
 84
 84
Distributions to member—
 (38) (38)
Contributions from member235
 —
 235
Balance, June 30, 2018$9,070
 $30
 $9,100



 Nine Months Ended September 30, 2018
(In millions)Membership Interest Undistributed Earnings (Losses) Member's Equity
Balance, December 31, 2017$8,835
 $(10) $8,825
Net income—
 65
 65
Distributions to member—
 (71) (71)
Balance, March 31, 2018$8,835
 $(16) $8,819
Net income—
 84
 84
Distributions to member—
 (38) (38)
Contributions from member235
 —
 235
Balance, June 30, 2018$9,070
 $30
 $9,100
Net income—

187

187
Distribution to member—

(123)
(123)
Contribution from parent2

—

2
Balance, September 30, 2018$9,072

$94

$9,166

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,		Three Months Ended
September 30,
Nine Months Ended
September 30,
(In millions)2019
2018
2019
20182019
2018
2019
2018
Operating revenues              
Electric operating revenues$531
 $531
 $1,090
 $1,067
$643
 $630
 $1,733
 $1,697
Revenues from alternative revenue programs(1) (10) 13
 10
(3) (4) 10
 6
Operating revenues from affiliates1
 2
 3
 3
2
 2
 5
 5
Total operating revenues531
 523
 1,106
 1,080
642
 628
 1,748
 1,708
Operating expenses              
Purchased power92
 94
 209
 224
116
 131
 325
 354
Purchased power from affiliates52
 46
 122
 98
65
 46
 188
 143
Operating and maintenance59
 60
 123
 133
85
 84
 208
 216
Operating and maintenance from affiliates52
 56
 107
 113
50
 52
 156
 167
Depreciation and amortization93
 92
 186
 188
95
 99
 281
 286
Taxes other than income90
 90
 182
 183
104
 104
 286
 288
Total operating expenses438
 438
 929
 939
515
 516
 1,444
 1,454
Operating income93
 85
 177
 141
127
 112
 304
 254
Other income and (deductions)              
Interest expense, net(34) (32) (68) (63)(33) (32) (100) (96)
Other, net7
 8
 14
 16
9
 7
 22
 23
Total other income and (deductions)(27) (24) (54) (47)(24) (25) (78) (73)
Income before income taxes66
 61
 123
 94
103
 87
 226
 181
Income taxes2
 7
 4
 9
5
 (2) 9
 7
Net income$64
 $54
 $119
 $85
$98
 $89
 $217
 $174
Comprehensive income$64
 $54
 $119
 $85
$98
 $89
 $217
 $174

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities      
Net income$119
 $85
$217
 $174
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization186
 188
281
 286
Deferred income taxes and amortization of investment tax credits10
 (8)12
 (5)
Other non-cash operating activities8
 24
43
 42
Changes in assets and liabilities:      
Accounts receivable(36) (31)(49) (36)
Receivables from and payables to affiliates, net4
 (11)4
 (9)
Inventories(20) 2
(23) 6
Accounts payable and accrued expenses(25) 77
(12) 104
Income taxes(23) 3
(23) (18)
Pension and non-pension postretirement benefit contributions(6) (11)(10) (11)
Other assets and liabilities(40) (91)(55) (137)
Net cash flows provided by operating activities177
 227
385
 396
Cash flows from investing activities      
Capital expenditures(298) (287)(455) (475)
Changes in PHI intercompany money pool(38) —
Other investing activities1
 2
2
 3
Net cash flows used in investing activities(335) (285)(453) (472)
Cash flows from financing activities      
Changes in short-term borrowings(40) (26)(28) 38
Issuance of long-term debt260
 100
260
 100
Retirement of long-term debt(117) (7)(118) (8)
Dividends paid on common stock(72) (50)(173) (128)
Contributions from parent129
 85
129
 85
Other financing activities(3) (4)(3) (4)
Net cash flows provided by financing activities157
 98
67
 83
(Decrease) increase in cash, cash equivalents and restricted cash(1) 40
(1) 7
Cash, cash equivalents and restricted cash at beginning of period53
 40
53
 40
Cash, cash equivalents and restricted cash at end of period$52
 $80
$52
 $47
      
Supplemental cash flow information      
(Decrease) increase in capital expenditures not paid$(18) $28
$(7) $15

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019
December 31, 2018September 30, 2019
December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$18
 $16
$18
 $16
Restricted cash and cash equivalents34
 37
34
 37
Accounts receivable, net      
Customer (net of allowance for uncollectible accounts of $13 and $20 as of June 30, 2019 and December 31, 2018, respectively)254
 225
Other (net of allowance for uncollectible accounts of $6 and $1 as of June 30, 2019 and December 31, 2018, respectively)110
 81
Customer (net of allowance for uncollectible accounts of $16 and $20 as of September 30, 2019 and December 31, 2018, respectively)258
 225
Other (net of allowance for uncollectible accounts of $8 and $1 as of September 30, 2019 and December 31, 2018, respectively)114
 81
Receivables from affiliates—
 1
—
 1
Receivable from PHI intercompany money pool38
 —
Inventories, net115
 93
118
 93
Regulatory assets262
 270
252
 270
Other10
 37
12
 37
Total current assets841

760
806

760
Property, plant and equipment, net (net of accumulated depreciation and amortization of $3,431 and $3,354 as of June 30, 2019 and December 31, 2018, respectively)6,623
 6,460
Property, plant and equipment, net (net of accumulated depreciation and amortization of $3,473 and $3,354 as of September 30, 2019 and December 31, 2018, respectively)6,734
 6,460
Deferred debits and other assets      
Regulatory assets601
 643
577
 643
Investments108
 105
109
 105
Prepaid pension asset306
 316
301
 316
Other77
 15
76
 15
Total deferred debits and other assets1,092

1,079
1,063

1,079
Total assets$8,556

$8,299
$8,603

$8,299

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Short-term borrowings$—
 $40
$12
 $40
Long-term debt due within one year8
 15
8
 15
Accounts payable175
 214
177
 214
Accrued expenses114
 126
144
 126
Payables to affiliates67
 62
65
 62
Customer deposits55
 54
56
 54
Regulatory liabilities7
 7
9
 7
Merger related obligation38
 38
38
 38
Current portion of DC PLUG obligation30
 30
30
 30
Other23
 42
25
 42
Total current liabilities517

628
564

628
Long-term debt2,852
 2,704
2,852
 2,704
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits1,114
 1,064
1,150
 1,064
Asset retirement obligations37
 37
41
 37
Non-pension postretirement benefit obligations25
 29
23
 29
Regulatory liabilities782
 822
749
 822
Other313
 275
311
 275
Total deferred credits and other liabilities2,271

2,227
2,274

2,227
Total liabilities5,640

5,559
5,690

5,559
Commitments and contingencies

 


 

Shareholder's equity      
Common stock1,765
 1,636
1,765
 1,636
Retained earnings1,151
 1,104
1,148
 1,104
Total shareholder's equity2,916
 2,740
2,913
 2,740
Total liabilities and shareholder's equity$8,556
 $8,299
$8,603
 $8,299

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Six Months Ended June 30, 2019Nine Months Ended September 30, 2019
(In millions)Common Stock Retained Earnings Total Shareholder's EquityCommon Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2018$1,636
 $1,104
 $2,740
$1,636
 $1,104
 $2,740
Net income—
 55
 55
—
 55
 55
Common stock dividends—
 (24) (24)—
 (24) (24)
Contributions from parent14
 —
 14
14
 —
 14
Balance, March 31, 20191,650
 1,135
 2,785
$1,650
 $1,135
 $2,785
Net income—
 64
 64
—
 64
 64
Common stock dividends—
 (48) (48)—
 (48) (48)
Contributions from parent115
 —
 115
115
 —
 115
Balance, June 30, 2019$1,765

$1,151

$2,916
$1,765
 $1,151
 $2,916
     
Six Months Ended June 30, 2018
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2017$1,470
 $1,063
 $2,533
Net income—
 31
 31
—
 98
 98
Common stock dividends—
 (25) (25)—
 (101) (101)
Balance, March 31, 20181,470
 1,069
 2,539
Net income—
 54
 54
Common stock dividends—
 (25) (25)
Contributions from parent85
 —
 85
Balance, June 30, 2018$1,555
 $1,098
 $2,653
Balance, September 30, 2019$1,765

$1,148

$2,913
 Nine Months Ended September 30, 2018
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2017$1,470
 $1,063
 $2,533
Net income—
 31
 31
Common stock dividends—
 (25) (25)
Balance, March 31, 2018$1,470
 $1,069
 $2,539
Net income—
 54
 54
Common stock dividends—
 (25) (25)
Contributions from parent85
 —
 85
Balance, June 30, 2018$1,555
 $1,098
 $2,653
Net income—
 89
 89
Common stock dividends—
 (78) (78)
Balance, September 30, 2018$1,555
 $1,109
 $2,664


DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,
Six Months Ended
June 30,		Three Months Ended
September 30,
Nine Months Ended
September 30,
(In millions)2019
2018
2019
20182019
2018
2019
2018
Operating revenues              
Electric operating revenues$261
 $255
 $568
 $558
$304
 $302
 $872
 $861
Natural gas operating revenues24
 28
 95
 106
20
 24
 116
 129
Revenues from alternative revenue programs—
 4
 1
 5
(6) —
 (6) 5
Operating revenues from affiliates2
 2
 3
 4
1
 2
 5
 6
Total operating revenues287

289

667

673
319

328

987

1,001
Operating expenses              
Purchased power86
 72
 193
 162
105
 96
 298
 258
Purchased fuel9
 12
 43
 53
8
 11
 51
 64
Purchased power from affiliate12
 30
 35
 76
14
 26
 50
 103
Operating and maintenance39
 36
 84
 94
43
 44
 127
 137
Operating and maintenance from affiliates38
 41
 76
 81
37
 38
 113
 119
Depreciation and amortization45
 43
 91
 88
46
 47
 138
 135
Taxes other than income14
 13
 28
 28
15
 15
 43
 43
Total operating expenses243

247

550

582
268

277

820

859
Operating income44

42

117

91
51

51

167

142
Other income and (deductions)              
Interest expense, net(15) (14) (30) (27)(15) (15) (45) (42)
Other, net5
 3
 7
 5
2
 2
 10
 7
Total other income and (deductions)(10)
(11)
(23)
(22)(13)
(13)
(35)
(35)
Income before income taxes34
 31
 94
 69
38
 38
 132
 107
Income taxes4
 5
 11
 12
5
 5
 16
 17
Net income$30

$26

$83

$57
$33

$33

$116

$90
Comprehensive income$30
 $26
 $83
 $57
$33
 $33
 $116
 $90

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,		Nine Months Ended
September 30,
(In millions)2019
20182019
2018
Cash flows from operating activities      
Net income$83
 $57
$116
 $90
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization91
 88
138
 135
Deferred income taxes and amortization of investment tax credits(5) 9
(2) 24
Other non-cash operating activities11
 14
21
 16
Changes in assets and liabilities:      
Accounts receivable15
 18
29
 13
Receivables from and payables to affiliates, net(11) (22)(7) (14)
Inventories(3) 4
(7) (3)
Accounts payable and accrued expenses6
 10
3
 18
Income taxes11
 16
11
 —
Pension and non-pension postretirement benefit contributions(1) —
(1) —
Other assets and liabilities(26) 22
(22) 13
Net cash flows provided by operating activities171

216
279

292
Cash flows from investing activities      
Capital expenditures(160) (166)(245) (254)
Other investing activities1
 1
1
 1
Net cash flows used in investing activities(159)
(165)(244)
(253)
Cash flows from financing activities      
Changes in short-term borrowings—
 (216)57
 (216)
Issuance of long-term debt—
 200
—
 200
Retirement of long-term debt—
 (4)—
 (4)
Dividends paid on common stock(70) (40)(105) (58)
Contributions from parent—
 150
—
 150
Changes in PHI intercompany money pool38
 —
Other financing activities—
 (2)—
 (3)
Net cash flows (used in) provided by financing activities(32)
88
(48)
69
(Decrease) increase in cash, cash equivalents and restricted cash(20) 139
(13) 108
Cash, cash equivalents and restricted cash at beginning of period24
 2
24
 2
Cash, cash equivalents and restricted cash at end of period$4

$141
$11

$110
      
Supplemental cash flow information      
(Decrease) increase in capital expenditures not paid$(17) $17
$(13) $20

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$3
 $23
$11
 $23
Restricted cash and cash equivalents1
 1
—
 1
Accounts receivable, net      
Customer (net of allowance for uncollectible accounts of $10 and $12 as of June 30, 2019 and December 31, 2018, respectively)123
 134
Other (net of allowance for uncollectible accounts of $2 and $1 as of June 30, 2019 and December 31, 2018, respectively)43
 46
Customer (net of allowance for uncollectible accounts of $10 and $12 as of September 30, 2019 and December 31, 2018, respectively)112
 134
Other (net of allowance for uncollectible accounts of $1 as of both September 30, 2019 and December 31, 2018)37
 46
Inventories, net      
Fossil Fuel5
 9
8
 9
Materials and supplies46
 37
47
 37
Renewable energy credits18
 8
Prepaid utility taxes15
 17
Regulatory assets59
 59
62
 59
Other2
 19
5
 10
Total current assets300

336
297

336
Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,380 and $1,329 as of June 30, 2019 and December 31, 2018, respectively)3,893
 3,821
Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,407 and $1,329 as of September 30, 2019 and December 31, 2018, respectively)3,941
 3,821
Deferred debits and other assets      
Regulatory assets224
 231
221
 231
Goodwill8
 8
8
 8
Prepaid pension asset178
 186
175
 186
Other80
 6
82
 6
Total deferred debits and other assets490

431
486

431
Total assets$4,683

$4,588
$4,724

$4,588

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Short-term borrowings$57
 $—
Long-term debt due within one year$91
 $91
91
 91
Accounts payable106
 111
90
 111
Accrued expenses43
 39
59
 39
Payables to affiliates25
 33
26
 33
Customer deposits36
 35
36
 35
Regulatory liabilities43
 59
43
 59
Borrowings from PHI intercompany money pool38
 —
Other16
 7
33
 7
Total current liabilities398
 375
435
 375
Long-term debt1,404
 1,403
1,404
 1,403
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits644
 628
655
 628
Non-pension postretirement benefits obligations16
 17
16
 17
Regulatory liabilities586
 606
580
 606
Other113
 50
114
 50
Total deferred credits and other liabilities1,359

1,301
1,365

1,301
Total liabilities3,161

3,079
3,204

3,079
Commitments and contingencies

 


 

Shareholder's equity      
Common stock914
 914
914
 914
Retained earnings608
 595
606
 595
Total shareholder's equity1,522

1,509
1,520

1,509
Total liabilities and shareholder's equity$4,683

$4,588
$4,724

$4,588

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Six Months Ended June 30, 2019Nine Months Ended September 30, 2019
(In millions)Common Stock Retained Earnings Total Shareholder's EquityCommon Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2018$914
 $595
 $1,509
$914
 $595
 $1,509
Net income—
 53
 53
—
 53
 53
Common stock dividends—
 (41) (41)—
 (41) (41)
Balance, March 31, 2019914
 607
 1,521
$914
 $607
 $1,521
Net income—
 30
 30
—
 30
 30
Common stock dividends—
 (29) (29)—
 (29) (29)
Balance, June 30, 2019$914
 $608
 $1,522
$914
 $608
 $1,522
Net income—
 33
 33
Common stock dividends—
 (35) (35)
Balance, September 30, 2019$914
 $606
 $1,520

Six Months Ended June 30, 2018Nine Months Ended September 30, 2018
(In millions)Common Stock Retained Earnings Total Shareholder's EquityCommon Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2017$764
 $571
 $1,335
$764
 $571
 $1,335
Net income—
 31
 31
—
 31
 31
Common stock dividends—
 (36) (36)—
 (36) (36)
Balance, March 31, 2018764
 566
 1,330
$764
 $566
 $1,330
Net income—
 26
 26
—
 26
 26
Common stock dividends—
 (4) (4)—
 (4) (4)
Contributions from parent150
 —
 150
150
 —
 150
Balance, June 30, 2018$914
 $588
 $1,502
$914
 $588
 $1,502
Net income—
 33
 33
Common stock dividends—
 (18) (18)
Balance, September 30, 2018$914
 $603
 $1,517


ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2019 2018 2019 20182019 2018 2019 2018
Operating revenues              
Electric operating revenues$275
 $265
 $547
 $576
$417
 $406
 $964
 $983
Revenues from alternative revenue programs(2) (1) (1) (3)1
 (1) —
 (4)
Operating revenues from affiliates1
 1
 1
 2
1
 1
 2
 2
Total operating revenues274
 265
 547
 575
419
 406
 966
 981
Operating expenses              
Purchased power125
 122
 257
 277
207
 188
 463
 465
Purchased power from affiliates6
 6
 13
 12
3
 10
 16
 21
Operating and maintenance41
 40
 88
 95
54
 52
 142
 146
Operating and maintenance from affiliates33
 35
 67
 70
32
 33
 99
 104
Depreciation and amortization40
 36
 71
 69
43
 38
 114
 107
Taxes other than income1
 1
 2
 3
1
 1
 4
 4
Total operating expenses246
 240
 498
 526
340
 322
 838
 847
Operating income28

25
 49

49
79

84
 128

134
Other income and (deductions)              
Interest expense, net(15) (16) (28) (32)(15) (16) (44) (48)
Other, net1
 1
 4
 1
1
 1
 5
 2
Total other income and (deductions)(14) (15) (24) (31)(14) (15) (39) (46)
Income before income taxes14
 10
 25
 18
65
 69
 89
 88
Income taxes—
 2
 1
 3
2
 8
 2
 12
Net income$14

$8

$24

$15
$63

$61

$87

$76
Comprehensive income$14
 $8
 $24
 $15
$63
 $61
 $87
 $76

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,		Nine Months Ended
September 30,
(In millions)2019
20182019
2018
Cash flows from operating activities      
Net income$24
 $15
$87
 $76
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization71
 69
114
 107
Deferred income taxes and amortization of investment tax credits2
 6
2
 24
Other non-cash operating activities7
 12
21
 24
Changes in assets and liabilities:      
Accounts receivable(11) (13)(44) (66)
Receivables from and payables to affiliates, net(9) (4)(4) (3)
Inventories(1) 4
(4) (2)
Accounts payable and accrued expenses16
 14
27
 21
Income taxes6
 3
5
 (3)
Pension and non-pension postretirement benefit contributions—
 (6)—
 (6)
Other assets and liabilities(44) (33)(18) (12)
Net cash flows provided by operating activities61
 67
186
 160
Cash flows from investing activities      
Capital expenditures(227) (170)(300) (247)
Other investing activities—
 (2)—
 (1)
Net cash flows used in investing activities(227) (172)(300) (248)
Cash flows from financing activities      
Changes in short-term borrowings13
 14
49
 37
Proceeds from short-term borrowings with maturities greater than 90 days—
 125
—
 125
Repayments of short-term borrowings with maturities greater than 90 days(125) —
(125) —
Issuance of long-term debt150
 —
150
 —
Retirement of long-term debt(9) (15)(13) (22)
Contributions from parent155
 —
Dividends paid on common stock(24) (19)(100) (46)
Contributions from parent155
 —
Other financing activities(1) —
(1) —
Net cash flows provided by financing activities159
 105
115
 94
(Decrease) increase in cash, cash equivalents and restricted cash(7) —
Increase in cash, cash equivalents and restricted cash1
 6
Cash, cash equivalents and restricted cash at beginning of period30
 31
30
 31
Cash, cash equivalents and restricted cash at end of period$23

$31
$31

$37
      
Supplemental cash flow information      
(Decrease) increase in capital expenditures not paid$(35) $14
$(37) $16

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$4
 $7
$13
 $7
Restricted cash and cash equivalents2
 4
3
 4
Accounts receivable, net      
Customer (net of allowance for uncollectible accounts of $11 and $18 as of June 30, 2019 and December 31, 2018, respectively)112
 95
Other (net of allowance for uncollectible accounts of $3 and $1 as of June 30, 2019 and December 31, 2018, respectively)50
 55
Customer (net of allowance for uncollectible accounts of $15 and $18 as of September 30, 2019 and December 31, 2018, respectively)142
 95
Other (net of allowance for uncollectible accounts of $5 and $1 as of September 30, 2019 and December 31, 2018, respectively)47
 55
Receivables from affiliates—
 1
1
 1
Inventories, net34
 33
37
 33
Prepaid utility taxes33
 —
9
 —
Regulatory assets57
 40
48
 40
Other7
 5
7
 5
Total current assets299
 240
307
 240
Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,179 and $1,137 as of June 30, 2019 and December 31, 2018, respectively)3,093
 2,966
Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,192 and $1,137 as of September 30, 2019 and December 31, 2018, respectively)3,124
 2,966
Deferred debits and other assets      
Regulatory assets374
 386
370
 386
Prepaid pension asset60
 67
56
 67
Other60
 40
59
 40
Total deferred debits and other assets494
 493
485
 493
Total assets(a)
$3,886
 $3,699
$3,916
 $3,699

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

(In millions)June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Short-term borrowings$27
 $139
$63
 $139
Long-term debt due within one year19
 18
19
 18
Accounts payable135
 154
139
 154
Accrued expenses36
 35
40
 35
Payables to affiliates21
 28
24
 28
Customer deposits26
 26
26
 26
Regulatory liabilities25
 18
25
 18
Other10
 4
11
 4
Total current liabilities299
 422
347
 422
Long-term debt1,310
 1,170
1,305
 1,170
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits546
 535
569
 535
Non-pension postretirement benefit obligations18
 17
18
 17
Regulatory liabilities388
 402
365
 402
Other44
 27
44
 27
Total deferred credits and other liabilities996
 981
996
 981
Total liabilities(a)
2,605
 2,573
2,648
 2,573
Commitments and contingencies

 


 

Shareholder's equity      
Common stock1,134
 979
1,134
 979
Retained earnings147
 147
134
 147
Total shareholder's equity1,281

1,126
1,268

1,126
Total liabilities and shareholder's equity$3,886

$3,699
$3,916

$3,699
__________
(a)ACE’s consolidated total assets include $19$18 million and $23 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $51$46 million and $59 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 — Variable Interest Entities for additional information.

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Six Months Ended June 30, 2019Nine Months Ended September 30, 2019
(In millions)Common Stock Retained Earnings Total Shareholder's EquityCommon Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2018$979
 $147
 $1,126
$979
 $147
 $1,126
Net income—
 10
 10
—
 10
 10
Common stock dividends—
 (12) (12)—
 (12) (12)
Contributions from parent5
 —
 5
5
 —
 5
Balance, March 31, 2019984
 145
 1,129
$984
 $145
 $1,129
Net income—
 14
 14
—
 14
 14
Common stock dividends—
 (12) (12)—
 (12) (12)
Contributions from parent150
 —
 150
150
 —
 150
Balance, June 30, 2019$1,134

$147
 $1,281
$1,134

$147
 $1,281
Net income—
 63
 63
Common stock dividends—
 (76) (76)
Balance, September 30, 2019$1,134
 $134
 $1,268

Six Months Ended June 30, 2018Nine Months Ended September 30, 2018
(In millions)Common Stock Retained Earnings Total Shareholder's EquityCommon Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2017$912
 $131
 $1,043
$912
 $131
 $1,043
Net income—
 7
 7
—
 7
 7
Common stock dividends—
 (9) (9)—
 (9) (9)
Balance, March 31, 2018912
 129
 1,041
$912
 $129
 $1,041
Net income—
 8
 8
—
 8
 8
Common stock dividends—
 (10) (10)—
 (10) (10)
Balance, June 30, 2018$912

$127
 $1,039
$912

$127
 $1,039
Net income—
 61
 61
Common stock dividends—
 (27) (27)
Balance, September 30, 2018$912
 $161
 $1,073


See the Combined Notes to Consolidated Financial Statements
54
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)

Note 1 — Significant Accounting Policies


1. Significant Accounting Policies (All Registrants)
Description of Business (All Registrants)
Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.
Name of Registrant  Business  Service 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. Five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions
     
Commonwealth Edison Company Purchase and regulated retail sale of electricity Northern Illinois, including the City of Chicago
  Transmission and distribution of electricity to retail customers  
PECO Energy Company Purchase and regulated retail sale of electricity and natural gas Southeastern Pennsylvania, including the City of Philadelphia (electricity)
  Transmission and distribution of electricity and distribution of natural gas to retail customers Pennsylvania counties surrounding the City of Philadelphia (natural gas)
Baltimore Gas and Electric Company Purchase and regulated retail sale of electricity and natural gas Central Maryland, including the City of Baltimore (electricity and natural gas)
  Transmission and distribution of electricity and distribution of natural gas to retail customers  
Pepco Holdings LLC Utility services holding company engaged, through its reportable segments Pepco, DPL and ACE Service Territories of Pepco, DPL and ACE
     
Potomac Electric 
Power Company		  Purchase and regulated retail sale of electricity  District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland
  Transmission and distribution of electricity to retail customers  
Delmarva Power &
Light Company
 Purchase and regulated retail sale of electricity and natural gas Portions of Delaware and Maryland (electricity)
  Transmission and distribution of electricity and distribution of natural gas to retail customers Portions of New Castle County, Delaware (natural gas)
Atlantic City Electric Company Purchase and regulated retail sale of electricity Portions of Southern New Jersey
  Transmission and distribution of electricity to retail customers  

Basis of Presentation (All Registrants)
Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services
at cost, including legal, human resources, financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
The accompanying consolidated financial statements as of JuneSeptember 30, 2019 and 2018 and for the three and sixnine 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, 2018 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

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

Note 1 — Significant Accounting Policies

the fiscal year ending December 31, 2019. 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.
New Accounting Standards (All Registrants)
New Accounting Standards Adopted in 2019: In 2019, the Registrants have adopted the following new authoritative accounting guidance issued by the FASB.
Leases. The Registrants applied the new guidance with the following transition practical expedients:
a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carryforwardcarry forward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases,
an implementation expedient which allows the requirements of the standard in the period of adoption with no restatement of prior periods, and
a land easement expedient which allows entities to not evaluate land easements under the new standard at adoption if they were not previously accounted for as leases.
The standard materially impacted the Registrants' Consolidated Balance Sheets but did not have a material impact in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders' Equity. The most significant impact was the recognition of the ROU assets and lease liabilities for operating leases. The operating ROU assets and lease liabilities recognized upon adoption are materially consistent with the balances presented in the Combined Notes to the Consolidated Financial Statements. See Note 5 - Leases for additional information.
See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information on new accounting standards issued and adopted as of January 1, 2019.
New Accounting Standards Issued and Not Yet Adopted as of JuneSeptember 30, 2019: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of JuneSeptember 30, 2019. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their financial statements. The Registrants have assessed other FASB issuances of new standards which are not listed below as the Registrants do not expect such standards to have a material impact to their financial statements.
Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. Exelon, Generation, ComEd, PHI and DPL do not expect the updated guidance to have a material impact to their financial statements. The standard is effective January 1, 2020, with early adoption permitted, and must be applied on a prospective basis.
Impairment of Financial Instruments (Issued June 2016). Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects the entity’sits 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, intangiblesinstrument based on historical experience, current conditions and goodwill.reasonable and supportable forecasts. The standard will be effective January 1, 2020 (with early adoption as of January 1, 2019 permitted) and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. This standard is primarily applicable to Generation's and the Utility Registrants' trade accounts receivable balances. The Registrants are currently assessing the impacts ofdo not expect that this standard.guidance will have a significant impact on their consolidated financial statements.

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

Note 1 — Significant Accounting Policies

Leases (All Registrants)
The Registrants recognize a ROU asset and lease liability for operating leases with a term of greater than one year. The ROU asset is included in Other deferred debits and other assets and the lease liability is included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using each Registrant’s incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. The Registrants include non-lease components, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability.
Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation and are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements on the Registrants’ Statements of Operations and Comprehensive Income.
Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation and are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues on the Registrants’ Statements of Operations and Comprehensive Income.
The Registrants’ operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. The Registrants generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all of the economic benefits. For new agreements entered after January 1, 2019, the Registrants will generally not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases.
See Note 5 —Leases for additional information.
2. Variable Interest Entities (All Registrants)(Exelon, Generation, PHI and ACE)
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 JuneSeptember 30, 2019 and December 31, 2018, Exelon, Generation, PHI and ACE collectively consolidated fiveseveral VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated Variable Interest EntitiesVIEs below). As of June 30, 2019 and December 31, 2018, Exelon and Generation collectively had significant interests in eight and seven, respectively,several other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated Variable Interest EntitiesVIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.

Consolidated VIEs
The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements of Exelon, Generation, PHI and ACE as of September 30, 2019 and December 31, 2018. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnote to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI and ACE.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

ConsolidatedNote 2 — Variable Interest Entities


 September 30, 2019 December 31, 2018
 Exelon
Generation
PHI (a)
 ACE Exelon Generation 
PHI (a)
 ACE
Cash and cash equivalents$168
 $168
 $—
 $—
 $414
 $414
 $—
 $—
Restricted cash and cash equivalents76
 73
 3
 3
 66
 62
 4
 4
Accounts receivable, net               
Customer163
 163
 —
 —
 146
 146
 —
 —
Other43
 43
 —
 —
 23
 23
 —
 —
Unamortized energy contract asset (b)
23
 23
 —
 —
 25
 25
 —
 —
Inventory, net               
Materials and supplies222
 222
 —
 —
 212
 212
 —
 —
Other current assets50
 48
 2
 —
 52
 49
 3
 —
Total current assets745

740

5
 3
 938

931

7
 4
Property, plant and equipment, net (c)
6,079
 6,079
 —
 —
 6,188
 6,188
 —
 —
NDT funds2,636
 2,636
 —
 —
 2,351
 2,351
 —
 —
Unamortized energy contract asset (b)
258
 258
 —
 —
 274
 274
 —
 —
Other noncurrent assets69
 52
 17
 15
 258
 232
 26
 19
Total noncurrent assets9,042

9,025

17
 15
 9,071

9,045

26
 19
Total assets$9,787

$9,765

$22
 $18
 $10,009

$9,976

$33
 $23
Long-term debt due within one year$556
 $535
 $21
 $19
 $87
 $66
 $21
 $18
Accounts payable148
 148
 —
 —
 96
 96
 —
 —
Accrued expenses58
 57
 1
 1
 73
 72
 1
 1
Unamortized energy contract liabilities10
 10
 —
 —
 15
 15
 —
 —
Other current liabilities30
 30
 —
 —
 3
 3
 —
 —
Total current liabilities802
 780
 22
 20
 274
 252
 22
 19
Long-term debt532
 504
 28
 26
 1,072
 1,025
 47
 40
Asset retirement obligations (d)
2,103
 2,103
 —
 —
 2,165
 2,165
 —
 —
Unamortized energy contract liabilities1
 1
 —
 —
 1
 1
 —
 —
Other noncurrent liabilities84
 84
 —
 —
 42
 42
 —
 —
Total noncurrent liabilities2,720
 2,692
 28
 26
 3,280
 3,233
 47
 40
Total liabilities$3,522
 $3,472
 $50
 $46
 $3,554
 $3,485
 $69
 $59
_________
(a)Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
(b)These are unrestricted assets to Exelon and Generation.
(c)Exelon’s and Generation’s balances include unrestricted assets of $41 million and $43 million as of September 30, 2019 and December 31, 2018, respectively.
(d)Exelon’s and Generation’s balances include liabilities with recourse of $5 million as of September 30, 2019 and December 31, 2018.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Variable Interest Entities


As of JuneSeptember 30, 2019 and December 31, 2018, Exelon's and Generation's consolidated VIEs consist of:
energy related companies involved in distributed generation, backup generation
Consolidated VIE or VIE groups:Reason entity is a VIE:Reason Generation is primary beneficiary:
CENG - A joint venture between Generation and EDF. Generation has a 50.01% equity ownership in CENG. See additional discussion below.Disproportionate relationship between equity interest and operational control as a result of the Nuclear Operating Services Agreement (NOSA) described further below.Generation conducts the operational activities.
EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. See additional discussion below.Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.Generation conducts the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by EGRP. Generation is a minority interest holder.Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.Generation conducts the operational activities.
Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&E through a PPA.The PPA contract absorbs variability through a performance guarantee.Generation conducts all activities.
Equity investment in distributed energy company - Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE (see Unconsolidated VIEs disclosure below).

Generation fully impaired this investment in the third quarter of 2019. See Note 7— Asset Impairments for additional information.
Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.Generation conducts the operational activities.
CENG - On April 1, 2014, Generation, CENG, and energy development
renewable energy project companies formed by Generationsubsidiaries of CENG executed the NOSA pursuant to build, own and operate renewable power facilities
certain retail power and gas companies for which Generation isconducts all activities associated with the sole supplieroperations of energy,the CENG fleet and
CENG.
As of June 30, 2019 provides corporate and December 31, 2018, Exelon's, PHI'sadministrative services to CENG and ACE's consolidated VIE consist of:
ACE Transition Funding (ATF), a special purpose entity formed by ACEthe CENG fleet for the purposeremaining life of securitizing authorized portionsthe CENG nuclear plants as if they were a part of ACE’s recoverable stranded costs through the issuance and sale of transition bonds.
As of June 30, 2019 and December 31, 2018, ComEd, PECO, BGE, Pepco and DPL did not have any material consolidated VIEs.
Exelon and Generation provided the following support to their respective consolidated VIEs:
Operating and capital fundingnuclear fleet, subject to the renewable energy project companies and there is limited recourse to Generation related to certain renewable energy project companies;
Approximately $6 million and $34 million asCENG member rights of June 30, 2019 and December 31, 2018, respectively, in credit support for the retail power and gas companies for which Generation is the sole supplier of energy.EDF.
Exelon and Generation, where indicated, provide the following support to CENG:
under PPAs 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.
Generation provided a $400 million loan to CENG. The loan balance was fully repaid by CENG in January 2019.
Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 16 — Commitments and Contingencies for additional information),
•
Generation andexecuted an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF shareagainst third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. See Note 22 — Commitments and Contingencies of the Exelon $688 million of contingent payment obligations2018 Form 10-K for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, andadditional information.
Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance.
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.
AsEGRP - EGRP is a collection of June 30, 2019wind and December 31, 2018, Exelon, PHIsolar project entities and ACE providedsome of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the followingsolar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support to their respective consolidated VIE:
Inin the caseform of ATF, proceedsa parental guarantee of debt, loans from the sale of each series of transition bonds by ATF were transferredcustomers in order to ACE in exchangeobtain the necessary funds for the transfer by ACE to ATFconstruction of the rightsolar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. Generation provides operating and capital funding to collect a non-bypassable Transition Bond Charge from ACE customers pursuantthe solar and wind entities for ongoing construction, operations and maintenance and there is limited recourse related to bondable stranded costs rate orders issued by the NJBPU in an amount sufficientGeneration related to fund the principalcertain solar and interest payments on transition bonds and related taxes, expenses and fees. During the three and six months ended June 30, 2019, ACE

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

Note 2 — Variable Interest Entities


transferred $3 millionIn 2017, Generation’s interests in EGRP were contributed to and $7 millionare pledged for the EGR IV non-recourse debt project financing structure. Refer to ATF, respectively. During the threeNote 11— Debt and six months ended June 30, 2018, ACE transferred $6 million and $14 million to ATF, respectively.Credit Agreements for additional information.
For eachAs 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 JuneSeptember 30, 2019 and December 31, 2018, are as follows:Exelon's, PHI's and ACE's consolidated VIE consists of:
 June 30, 2019 December 31, 2018
 
Exelon(a)
 Generation 
PHI(a)
 ACE 
Exelon(a)
 Generation 
PHI(a)
 ACE
Current assets$649
 $646
 $3
 $2
 $938
 $931
 $7
 $4
Noncurrent assets9,204
 9,184
 20
 17
 9,071
 9,045
 26
 19
Total assets$9,853

$9,830

$23
 $19

$10,009

$9,976

$33
 $23
Current liabilities715
 694
 21
 20
 $274
 $252
 $22
 $19
Noncurrent liabilities2,861
 2,827
 34
 31
 3,280
 3,233
 47
 40
Total liabilities$3,576

$3,521

$55
 $51

$3,554

$3,485

$69
 $59
_________
(a)Consolidated VIEs:Includes certain purchase accounting adjustments not pushed down toReason entity is a VIE:Reason ACE is the ACE standalone entity.

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 June 30, 2019 and December 31, 2018, these assets and liabilities primarily consisted of the following:
 June 30, 2019 December 31, 2018
 
Exelon(a)

Generation
PHI(a)
 ACE 
Exelon(a)
 Generation 
PHI(a)
 ACE
Cash and cash equivalents$106
 $106
 $—
 $—
 $414
 $414
 $—
 $—
Restricted cash and cash equivalents75
 73
 2
 2
 66
 62
 4
 4
Accounts receivable, net               
Customer161
 161
 —
 —
 146
 146
 —
 —
Other39
 39
 —
 —
 23
 23
 —
 —
Inventory, net               
Materials and supplies217
 217
 —
 —
 212
 212
 —
 —
Other current assets28
 27
 1
 —
 52
 49
 3
 —
Total current assets626

623

3
 2
 913

906

7
 4
Property, plant and equipment, net6,084
 6,084
 —
 —
 6,145
 6,145
 —
 —
NDT funds2,589
 2,589
 —
 —
 2,351
 2,351
 —
 —
Other noncurrent assets227
 207
 20
 17
 258
 232
 26
 19
Total noncurrent assets8,900

8,880

20
 17
 8,754

8,728

26
 19
Total assets$9,526

$9,503

$23
 $19
 $9,667

$9,634

$33
 $23
Long-term debt due within one year$560
 $540
 $20
 $19
 $87
 $66
 $21
 $18
Accounts payable89
 89
 —
 —
 96
 96
 —
 —
Accrued expenses52
 51
 1
 1
 72
 72
 1
 1
Unamortized energy contract liabilities11
 11
 —
 —
 15
 15
 —
 —
Other current liabilities3
 3
 —
 —
 3
 3
 —
 —
Total current liabilities715
 694
 21
 20
 273
 252
 22
 19
Long-term debt558
 524
 34
 31
 1,072
 1,025
 47
 40
Asset retirement obligations2,218
 2,218
 —
 —
 2,160
 2,160
 —
 —
Unamortized energy contract liabilities—
 —
 —
 —
 1
 1
 —
 —
Other noncurrent liabilities77
 77
 —
 —
 42
 42
 —
 —
Total noncurrent liabilities2,853
 2,819
 34
 31
 3,275
 3,228
 47
 40
Total liabilities$3,568
 $3,513
 $55
 $51
 $3,548
 $3,480
 $69
 $59
_________
primary beneficiary:
(a)ACE Transition Funding - A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds. Proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees.Includes certainACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ACETF. The bondholders also have a variable interest for the investment made to purchase accounting adjustments not pushed down to the transition bonds.ACE standalone entity.controls the servicing activities.
Unconsolidated Variable Interest EntitiesVIEs
Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts

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

(commercial (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.
As of June 30, 2019 and December 31, 2018, 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 for which Generation has concluded that consolidation is not required.
As of June 30, 2019 and December 31, 2018, the Utility Registrants did not have any material unconsolidated VIEs.
As of JuneSeptember 30, 2019 and December 31, 2018, Exelon and Generation had significant unconsolidated variable interests in eight and sevenseveral VIEs respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; includingbeneficiary. These interests include certain equity method investments and certain commercial agreements. Exelon and Generation only include unconsolidated VIEs that are individually material in the tables below. However, Exelon and Generation have several individually immaterial VIEs that in aggregate represent a total investment of $16 million and $12 million, as of June 30, 2019, and $15 million and $13 million as of December 31, 2018, respectively. These immaterial VIEs are equity and debt securities in energy development companies. As of June 30, 2019 and December 31, 2018, the maximum exposure to loss related to these securities included in Investments in Exelon’s and Generation’s Consolidated Balance Sheets is limited to $16 million and $12 million, and $15 million and $13 million, respectively. 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.



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

The following tables presenttable presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities:
June 30, 2019
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
Total assets(a)
$603
 $453
 $1,056
Total liabilities(a)
33
 225
 258
Exelon's ownership interest in VIE(a)
—
 203
 203
Other ownership interests in VIE(a)
571
 25
 596
Registrants’ maximum exposure to loss:    
Carrying amount of equity method investments—
 203
 203
Contract intangible asset7
 —
 7
December 31, 2018
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
September 30, 2019 December 31, 2018
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total 
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
Total assets(a)
$597
 $472
 $1,069
$614
 $453
 $1,067
 $597
 $472
 $1,069
Total liabilities(a)
37
 222
 259
36
 224
 260
 37
 222
 259
Exelon's ownership interest in VIE(a)
—
 223
 223
—
 201
 201
 —
 223
 223
Other ownership interests in VIE(a)
560
 27
 587
587
 28
 615
 560
 27
 587
Registrants’ maximum exposure to loss:    
    
     

Carrying amount of equity method investments—
 223
 223
—
 12
 12
 —
 223
 223
Contract intangible asset7
 —
 7
_________
(a)These items represent amounts in the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
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
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Variable Interest Entities


As of their variable interests in these VIEs.September 30, 2019 and December 31, 2018, Exelon's and Generation's unconsolidated VIEs consist of:
Unconsolidated VIE groups:Reason entity is a VIE:Reason Generation is not the primary beneficiary:
Equity investments in distributed energy companies -

1) Generation has a 90% equity ownership in a distributed energy company.
2) Generation, via a consolidated VIE, has a 90% equity ownership in another distributed energy company (See Consolidated VIEs disclosure above).

Generation fully impaired these investments in the third quarter of 2019. See Note 7— Asset Impairments for additional information.
Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.Generation does not conduct the operational activities.
Energy Purchase and Sale agreements - Generation has several energy purchase and sale agreements with generating facilities.PPA contracts that absorb variability through fixed pricing.Generation does not conduct the operational activities.

3. Mergers, Acquisitions and Dispositions (Exelon and Generation)
Acquisition of Handley Generating Station
On November 7, 2017, ExGen Texas Power, LLC (EGTP), and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware, which resulted in Exelon and Generation deconsolidating EGTP's assets and liabilities from their consolidated financial statements. 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, which closed on April 4, 2018 for a purchase price of $62 million.
Disposition of Oyster Creek
On July 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and a private letter ruling from the IRS, which were satisfied in the second quarter 2019. The sale was completed on July 1, 2019. Exelon and Generation expect therecognized a loss on the sale which will be recognized in the third quarter, to bewhich was immaterial.

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

Under the terms of the transaction, Generation transferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events.
As a result of the transaction, in the third quarter of 2018, Exelon and Generation reclassified certain Oyster Creek assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. Exelon and Generation had $863 million and $759 million of Assets and Liabilities held for sale, respectively, at June 30, 2019 and $897 million and $777 million of Assets and Liabilities held for sale, respectively, at December 31, 2018. Upon remeasurement of the Oyster Creek ARO, Exelon and Generation recognized an $84 million and a $9 million pre-tax charge to Operating and maintenance expense in the third quarter of 2018 and in the second quarter of 2019, respectively. See Note 13 -— Nuclear Decommissioning for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Mergers, Acquisitions and Dispositions

Other Asset Disposition
On February 28, 2018, Generation completed the sale of its interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution systems for $87 million, resulting in a pre-tax gain which is included within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the sixnine months ended JuneSeptember 30, 2018. In June 2018, additional proceeds were received, and a pre-tax gain was recorded within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
4. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution and transmission services.
See Note 3 — Revenue from Contracts with Customers of the Exelon 2018 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.
Contract Balances (All Registrants)
Contract Assets and Liabilities
Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Accounts receivable, net - Customer, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets.
Generation records contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. Generation records contract liabilities within Other current liabilities and Other noncurrent liabilities within 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 a rollforward of the contract assets and liabilities reflected in Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to JuneSeptember 30, 2019:
 Contract Assets Contract Liabilities Contract Assets Contract Liabilities
 Exelon Generation Exelon Generation Exelon Generation Exelon Generation
Balance as of January 1, 2018 $283
 $283
 $35
 $35
 $283
 $283
 $35
 $35
Consideration received or due (146) (146) 179
 465
 (146) (146) 179
 465
Revenues recognized 50
 50
 (187) (458) 50
 50
 (187) (458)
Balance at December 31, 2018 187
 187
 27
 42
 187
 187
 27
 42
Consideration received or due (44) (44) 38
 115
 (109) (109) 65
 198
Revenues recognized 53
 53
 (44) (131) 92
 92
 (66) (192)
Balance at June 30, 2019 $196
 $196
 $21
 $26
Balance at September 30, 2019 170
 170
 26
 48

The Utility Registrants do not have any contract assets. The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of JuneSeptember 30, 2019 and December 31, 2018, the Utility Registrants' contract liabilities were immaterial.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers

Transaction Price Allocated to Remaining Performance Obligations (All Registrants)
The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of JuneSeptember 30, 2019. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
This disclosure excludes Generation's power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.
2019 2020 2021 2022 2023 and thereafter Total2019 2020 2021 2022 2023 and thereafter Total
Exelon$274
 $275
 $93
 $68
 $248
 $958
156
 341
 142
 74
 244
 957
Generation355
 343
 118
 72
 248
 1,136
215
 442
 197
 89
 244
 1,187

Revenue Disaggregation (All Registrants)
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 18 — Segment Information for the presentation of the Registrant's revenue disaggregation.
5. Leases (All Registrants)
Lessee
The Registrants have operating leases for which they are the lessees. The following tables outline the significant types of operating leases at each registrant and other terms and conditions of the lease agreements. The Registrants do not have material finance leases.
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Contracted generation● ●              
Real estate● ● ● ● ● ● ● ● ●
Vehicles and equipment● ● ● ● ● ● ● ● ●

(in years)Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Remaining lease terms1-87 1-37 1-6 1-15 1-87 1-13 1-13 1-13 1-8
Options to extend the term3-30 3-30 5 N/A N/A 3-30 5 3-30 N/A
Options to terminate within2-14 2 4 N/A 3 N/A N/A N/A N/A
The components of lease costs for the three months ended September 30, 2019 were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating lease costs$97
 $73
 $1
 $—
 $8
 $12
 $3
 $3
 $2
Variable lease costs79
 74
 —
 —
 1
 1
 —
 —
 —
Short-term lease costs5
 5
 —
 —
 —
 —
 —
 —
 —
Total lease costs (a)
$181
 $152
 $1
 $—
 $9
 $13
 $3
 $3
 $2
__________
(a)Excludes $29 million, $28 million, $1 million and $1 million of sublease income recorded at Exelon, Generation, PHI and DPL, respectively
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Leases
(in years)Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Remaining lease terms1-87 1-37 1-6 1-15 1-87 1-13 1-13 1-13 1-8
Options to extend the term3-30 3-30 5 N/A N/A 3-30 5 3-30 N/A
Options to terminate within1-4 2 4 N/A 3 N/A N/A N/A N/A

The components of lease costs for the threenine months ended JuneSeptember 30, 2019 were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating lease costs$252
 $180
 $2
 $1
 $25
 $35
 $9
 $10
 $5
Variable lease costs229
 214
 1
 —
 1
 5
 2
 2
 1
Short-term lease costs16
 16
 —
 —
 —
 —
 —
 —
 —
Total lease costs (a)
$497
 $410
 $3
 $1
 $26
 $40
 $11
 $12
 $6
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating lease costs$87
 $61
 $1
 $—
 $9
 $13
 $3
 $4
 $3
Variable lease costs77
 72
 1
 —
 1
 2
 1
 —
 1
Short-term lease costs3
 3
 —
 —
 —
 —
 —
 —
 —
Total lease costs (a)
$167
 $136
 $2
 $—
 $10
 $15
 $4
 $4
 $4
__________
(a)Excludes $16$48 million, $12$42 million, $4$6 million and $4$6 million of sublease income recorded at Exelon, Generation, PHI and DPL.

The components of lease costs for the six months ended June 30, 2019 were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating lease costs$155
 $107
 $2
 $—
 $17
 $23
 $6
 $7
 $4
Variable lease costs150
 140
 1
 —
 1
 4
 1
 1
 1
Short-term lease costs11
 11
 —
 —
 —
 —
 —
 —
 —
Total lease costs (a)
$316
 $258
 $3
 $—
 $18
 $27
 $7
 $8
 $5
__________
(a)Excludes $19 million, $14 million, $5 million and $5 million of sublease income recorded at Exelon, Generation, PHI and DPL.DPL, respectively.
The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets as of JuneSeptember 30, 2019:
Exelon(a)
 
Generation(a)
 ComEd PECO BGE PHI Pepco DPL ACE
Exelon(a)
 
Generation(a)
 ComEd PECO BGE PHI Pepco DPL ACE
Operating lease ROU assets                                  
Other deferred debits and other assets$1,412
 $982
 $11
 $2
 $91
 $309
 $67
 $74
 $24
$1,374
 $926
 $10
 $2
 $83
 $304
 $66
 $75
 $24
                                  
Operating lease liabilities                                  
Other current liabilities250
 173
 3
 1
 32
 36
 8
 11
 6
242
 170
 3
 —
 32
 35
 8
 11
 5
Other deferred credits and other liabilities1,353
 981
 9
 1
 65
 280
 60
 72
 19
1,355
 949
 8
 1
 50
 279
 60
 74
 19
Total operating lease liabilities$1,603
 $1,154
 $12
 $2
 $97
 $316
 $68
 $83
 $25
$1,597
 $1,119
 $11
 $1
 $82
 $314
 $68
 $85
 $24
__________
(a)Exelon's and Generation's operating ROU assets and lease liabilities include $595$542 million and $744$703 million, respectively, related to contracted generation.
The weighted average remaining lease terms, in years, and discount rates for operating leases as of JuneSeptember 30, 2019 were as follows:
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Remaining lease term9.9
 10.6
 4.9
 4.4
 5.4
 9.2
 9.7
 9.6
 5.2
10.1
 10.6
 4.7
 4.3
 5.6
 9.0
 9.6
 9.5
 5.3
Discount rate4.6% 4.8% 3.1% 3.4% 3.6% 4.1% 3.8% 3.9% 3.5%4.5% 4.8% 3.1% 3.3% 3.6% 4.0% 3.7% 3.7% 3.3%


Future minimum lease payments for operating leases as of September 30, 2019 were as follows:
YearExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
2019$65
 $50
 $1
 $—
 $1
 $11
 $3
 $2
 $2
2020289
 203
 3
 1
 34
 45
 10
 13
 5
2021246
 162
 3
 —
 31
 43
 9
 12
 5
2022179
 113
 2
 —
 16
 42
 9
 12
 4
2023148
 100
 1
 —
 —
 41
 8
 11
 4
Remaining years1,123
 837
 2
 —
 19
 197
 43
 53
 6
Total2,050
 1,465
 12
 1
 101
 379
 82
 103
 26
Interest453
 346
 1
 —
 19
 65
 14
 18
 2
Total operating lease liabilities$1,597
 $1,119
 $11
 $1
 $82
 $314
 $68
 $85
 $24

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

Note 5 — Leases

Future minimum lease payments for operating leases as of June 30, 2019 were as follows:
YearExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
2019$149
 $104
 $2
 $1
 $17
 $23
 $6
 $5
 $4
2020291
 202
 3
 1
 34
 44
 9
 12
 5
2021246
 161
 3
 —
 31
 42
 9
 12
 5
2022177
 112
 2
 —
 16
 41
 8
 11
 4
2023141
 99
 1
 —
 —
 39
 8
 10
 3
Remaining years1,051
 834
 2
 —
 19
 196
 43
 52
 6
Total2,055
 1,512
 13
 2
 117
 385
 83
 102
 27
Interest452
 358
 1
 —
 20
 69
 15
 19
 2
Total operating lease liabilities$1,603
 $1,154
 $12
 $2
 $97
 $316
 $68
 $83
 $25

Future minimum lease payments for operating leases under the prior lease accounting guidance as of December 31, 2018 were as follows:
Year
Exelon(a)(b)
 
Generation(a)(b)
 
ComEd(a)(c)
 
PECO(a)(c)
 
BGE(a)(c)(d)(e)
 
PHI(a)
 
Pepco(a)
 
DPL(a)(c)
 
ACE(a)
2019$140
 $33
 $7
 $5
 $35
 $48
 $11
 $14
 $7
2020149
 46
 5
 5
 35
 46
 10
 13
 6
2021143
 46
 4
 5
 33
 43
 9
 12
 5
2022126
 47
 4
 5
 18
 42
 8
 12
 5
202397
 46
 3
 5
 3
 39
 8
 10
 4
Remaining years723
 545
 —
 —
 19
 159
 40
 35
 5
Total minimum future lease payments$1,378
 $763
 $23
 $25
 $143
 $377
 $86
 $96
 $32
__________
(a)Includes amounts related to shared use land arrangements.
(b)Excludes Generation’s contingent operating lease payments associated with contracted generation.
(c)Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd's, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectively. Also includes amounts related to shared use land arrangements.
(d)Includes all future lease payments on a 99-year real estate lease that expires in 2106.
(e)The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022, respectively.
Cash paid for amounts included in the measurement of lease liabilities for the sixnine months ended JuneSeptember 30, 2019 were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating cash flows from operating leases$142
 $101
 $2
 $—
 $16
 $19
 $5
 $4
 $3
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating cash flows from operating leases$225
 $156
 $2
 $—
 $32
 $29
 $7
 $6
 $4

ROU assets obtained in exchange for lease obligations for the sixnine months ended JuneSeptember 30, 2019 were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating leases$30
 $7
 $6
 $—
 $1
 $15
 $6
 $6
 $3
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating leases$70
 $11
 $6
 $—
 $1
 $20
 $7
 $9
 $4


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

Lessor
The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and other terms and conditions of their lease agreements.
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Contracted generation● ●              
Real estate● ● ● ● ● ● ● ● ●
(in years)Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Remaining lease terms1-84 1-33 1-18 1-84 24 1-14 2-7 13-14 1-3
Options to extend the term1-79 1-5 5-79 5-50 N/A 5 N/A N/A N/A
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Leases

The components of lease income for the three months ended JuneSeptember 30, 2019 were as follows:
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating lease income$14
 $12
 $—
 $—
 $—
 $1
 $—
 $1
 $—
$30
 $29
 $—
 $—
 $—
 $1
 $—
 $1
 $—
Variable lease income77
 74
 —
 —
 —
 3
 —
 3
 —
80
 80
 —
 —
 —
 —
 —
 —
 —

The components of lease income for the sixnine months ended JuneSeptember 30, 2019 were as follows:
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating lease income$18
 $15
 $—
 $—
 $—
 $2
 $—
 $2
 $—
$48
 $44
 $—
 $—
 $—
 $3
 $—
 $3
 $—
Variable lease income129
 126
 —
 —
 —
 3
 —
 3
 —
209
 206
 —
 —
 —
 3
 —
 3
 —

Future minimum lease payments to be recovered under operating leases as of JuneSeptember 30, 2019 were as follows:
YearExelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
2019$33
 $31
 $—
 $—
 $—
 $2
 $—
 $2
 —
$4
 $3
 $—
 $—
 $—
 $1
 $—
 $1
 $—
202051
 46
 —
 —
 —
 4
 —
 3
 —
51
 46
 —
 —
 —
 4
 —
 3
 —
202151
 46
 —
 —
 —
 4
 1
 3
 —
50
 45
 —
 —
 —
 4
 1
 3
 —
202250
 45
 —
 —
 —
 5
 —
 4
 —
50
 45
 —
 —
 —
 5
 —
 4
 —
202349
 45
 —
 —
 —
 4
 —
 3
 —
49
 45
 —
 —
 —
 4
 —
 3
 —
Remaining years314
 271
 1
 3
 1
 38
 —
 38
 —
314
 271
 1
 3
 1
 38
 —
 38
 —
Total$548
 $484
 $1
 $3
 $1
 $57
 $1
 $53
 $—
$518
 $455
 $1
 $3
 $1
 $56
 $1
 $52
 $—


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

Note 6 — Regulatory Matters

6. Regulatory Matters (All Registrants)
As discussed in Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The following discusses developments in 2019 and updates to the 2018 Form 10-K.
Utility Regulatory Matters (Exelon and the Utility Registrants)
Distribution Base Rate Case Proceedings
The following tables show the completed and pending distribution base rate case proceedings in 2019.
Completed Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateRequested Revenue Requirement (Decrease) Increase Approved Revenue Requirement (Decrease) Increase Approved ROE Approval DateRate Effective DateFiling DateRequested Revenue Requirement (Decrease) Increase Approved Revenue Requirement (Decrease) Increase Approved ROE Approval DateRate Effective Date
ComEd - Illinois (Electric)April 16, 2018$(23) $(24) 8.69%
December 4, 2018January 1, 2019April 16, 2018$(23) $(24) 8.69%
December 4, 2018January 1, 2019
PECO - Pennsylvania (Electric)March 29, 2018$82
 $25
 N/A
(a) 
December 20, 2018January 1, 2019March 29, 2018$82
 $25
 N/A
(a) 
December 20, 2018January 1, 2019
BGE - Maryland (Natural Gas)June 8, 2018 (amended October 12, 2018)$61
 $43
 9.8% January 4, 2019June 8, 2018 (amended October 12, 2018)$61
 $43
 9.8% January 4, 2019January 4, 2019
ACE - New Jersey (Electric)August 21, 2018 (amended November 19, 2018)$122
(b) 
$70
(b) 
9.6% March 13, 2019April 1, 2019August 21, 2018 (amended November 19, 2018)$122
(b) 
$70
(b) 
9.6% March 13, 2019April 1, 2019
Pepco - Maryland (Electric)January 15, 2019 (amended May 16, 2019)$27
 $10
 9.6% August 12, 2019August 13, 2019
__________
(a)The PECO rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.
(b)Requested and approved increases are before New Jersey sales and use tax.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Regulatory Matters

Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateRequested Revenue Requirement Increase (Decrease)Requested ROEExpected Approval Timing
Pepco - Maryland (Electric)January 15, 2019 (amended May 16, 2019)$27
10.3%Third quarter of 2019
ComEd - Illinois (Electric)(a)
April 8, 2019$(6)8.91%December 2019
BGE - Maryland (Electric)May 24, 2019$74
10.3%December 2019
BGE - Maryland (Natural Gas)May 24, 2019$59
10.3%December 2019
Pepco - District of Columbia (Electric)(b)
May 30, 2019$162
10.3%Second quarter of 2020
Registrant/JurisdictionFiling DateRequested Revenue Requirement (Decrease) IncreaseRequested ROEExpected Approval Timing
ComEd - Illinois (Electric)(a)
April 8, 2019$(6)8.91%December 2019
BGE - Maryland (Electric)(b)
May 24, 2019 (amended October 4, 2019)$74
10.3%December 2019
BGE - Maryland (Natural Gas)(b)
May 24, 2019 (amended October 4, 2019)$59
10.3%December 2019
Pepco - District of Columbia (Electric)(c)
May 30, 2019 (amended September 16, 2019)$160
10.3%Fourth quarter of 2020
__________
(a)Reflects an increase of $57 million for the initial revenue requirement for 2019 and a decrease of $63 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.53%. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on ComEd's distribution formula rate filings.
(b)
On October 25, 2019, BGE filed a settlement agreement with the MDPSC. The settlement provides for an increase to BGE’s annual electric and natural gas distribution rates of $18 million and $45 million, respectively.
(c)Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $85$84 million, $40 million and $37$36 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.

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

Transmission Formula Rates
Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation).
For 2019, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:
Registrant(a)
Initial Revenue Requirement Increase (Decrease)Annual Reconciliation Increase (Decrease)Total Revenue Requirement Increase (Decrease) 
Allowed Return on Rate Base(c)
Allowed ROE(d)
Initial Revenue Requirement Increase (Decrease)Annual Reconciliation (Decrease) IncreaseTotal Revenue Requirement Increase (Decrease) 
Allowed Return on Rate Base(c)
Allowed ROE(d)
ComEd$21
$(16)$5
 8.21%11.50%$21
$(16)$5
 8.21%11.50%
BGE(10)(23)(19)
(b) 
7.35%10.50%(10)(23)(19)
(b) 
7.35%10.50%
Pepco15
11
26

7.75%10.50%15
11
26

7.75%10.50%
DPL17
(1)16

7.14%10.50%17
(1)16

7.14%10.50%
ACE11
(2)9

7.79%10.50%11
(2)9

7.79%10.50%
__________
(a)
All rates are effective June 2019, subject to review by the FERC and other parties, which is due by the fourth quarter of 2019.
(b)The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $14 million to recover the costs of providing transmission service to specifically designated load by BGE.
(c)Represents the weighted average debt and equity return on transmission rate bases.
(d)As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Regulatory Matters

at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.
Pending Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. PECO’s initial formula rate filing included a requested increase of  $22 million to PECO’s annual transmission revenue requirement, which reflected a ROE of  11%, inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures.
Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.
On July 22, 2019, PECO and other parties filed with FERC a settlement agreement, which includes a ROE of 10.35%, inclusive of a 50 basis point adder for being a member of a RTO. The settlement isdid not expected to have a material impact on PECO’s 2017, 2018, or 2019 annual transmission revenue requirements. A final order from FERC is not expected prior tobefore the fourthend of the first quarter of 2019.2020. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.

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

Other State Regulatory Matters
Energy Efficiency Formula Rate.ComEd filed its annual energy efficiency formula rate update with the ICC on May 23, 2019. The filing establishes the revenue requirement used to set the rates that will take effect in January 2020 after the ICC’s review and approval. The revenue requirement requested is based on a reconciliation of the 2018 actual costs plus projected 2019 and 2020 expenditures.
RegistrantInitial Revenue Requirement Increase (Decrease)Annual Reconciliation Increase (Decrease)Total Revenue Requirement Increase (Decrease) Requested Return on Rate BaseRequested ROE
ComEd$53
$(2)$51
(a) 
6.53%8.91%
__________
(a)The requested revenue requirement increase provides for a weighted average debt and equity return on rate base of 6.53% inclusive of an allowed ROE of 8.91%. The ROE reflects the average rate on 30-year treasury notes plus 580 basis points. The ROE applicable to the 2018 reconciliation year is 10.91% and the return on rate base is 7.49%, which include the Performance Adjustment, which can either increase or decrease the ROE by up to a maximum of 200 basis points.
Maryland Regulatory Matters
Maryland Alternative Rate Plans Rulemaking (Exelon, BGE, PHI, Pepco and DPL). On August 9, 2019, the MDPSC issued an order in which the MDPSC determined that it is now appropriate to move forward to implement alternative rate plans in Maryland. The MDPSC found that a multi-year rate plan, based on a historic test year and allowing up to three future test years, can produce just and reasonable rates. A working group has been convened to develop and submit a detailed implementation report to the MDPSC by December 20, 2019. The MDPSC will issue another order on next steps by January 30, 2020. BGE, Pepco and DPL cannot predict the outcome or the potential financial impact, if any, on BGE, Pepco or DPL.
New Jersey Regulatory Matters
ACE Infrastructure Investment Program Filing (Exelon, PHI and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s Infrastructure Investment Program (IIP) proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP allowed for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Regulatory Matters

for a recovery totaling $96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement.
New Jersey Clean Energy Legislation (Exelon, PHI and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Electric distribution utilities in New Jersey, including ACE, began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the utility’s procurement of the ZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information.
Other Federal Regulatory Matters
Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. As a result of the FERC’s order, ComEd, BGE, Pepco, DPL and ACE took a charge to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017 reducing their associated transmission-related income tax regulatory assets for the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula. See above for additional information regarding PECO's transmission formula rate filing.
On December 18, 2017, BGE filed for clarification and rehearing of FERC’s November 16, 2017 order and on February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.

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

On September 7, 2018, FERC issued orders rejecting BGE’s December 18, 2017 request for rehearing and clarification and ComEd's, Pepco's, DPL's and ACE's February 23, 2018 (as amended on July 9, 2018) filings, citing the lack of timeliness of the requests to recover amounts that would have been previously amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement, consistent with its November 16, 2017 order.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and refund TCJA transmission-related income tax regulatory liabilities for the prospective period starting on October 1, 2018. In addition, on October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order. On November 2, 2018, BGE filed an appeal of FERC’s September 7, 2018 order to the Court of Appeals for the D.C. Circuit. On April 26, 2019, FERC issued an order accepting ComEd’s, BGE’s, Pepco’s, DPL’s, and ACE’s October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. ComEd, BGE, Pepco, DPL, and ACE cannot predict the outcome of these proceedings.
If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be up to approximately $78$80 million, $52 million, $16 million, $10$12 million, $3$4 million, $5$6 million and $2 million, respectively, as of JuneSeptember 30, 2019.
Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2018, unless noted below. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on the specific regulatory assets and liabilities.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Regulatory Matters

ComEd. Regulatory assets increased $88$122 million primarily due to an increase of $117$186 million in Energy Efficiency Costs and $32 million Renewable Energy partially offset by a decrease of $38$97 million in Electric Distribution Formula Rate Annual Reconciliations.
PECO. Regulatory assets increased $62 million primarily due to an increase of $95 million in Deferred Income Taxes offset by a $34 million decrease in Electric Energy and Natural Gas Costs.
BGE. Regulatory liabilities decreased $71$90 million primarily due to a decrease of $31$40 million in Deferred Income Taxes and $29$43 million in Removal Costs.
Pepco. Regulatory assets decreased $50$84 million primarily due to a decrease of $21$39 million in Electric Energy and Natural Gas Costs, and $16$26 million in DC PLUG charge.charge and $14 million in AMI Programs - Deployment Costs and Legacy Meters. Regulatory liabilities decreased by $71 million primarily due to a decrease of $73 million in Deferred Income Taxes.
DPL. Regulatory liabilities decreased $36$42 million primarily due to a decrease of $21$29 million in Deferred Income Taxes and $10 million in Electric Energy and Natural Gas Costs.
ACE.Regulatory liabilities decreased $30 million primarily due to a decrease of $32 million in Deferred Income Taxes.
Capitalized Ratemaking Amounts Not Recognized (Exelon and the Utility Registrants)
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.
Exelon 
ComEd(a)
 PECO 
BGE(b)
 PHI 
Pepco(c)
 
DPL(c)
 ACEExelon 
ComEd(a)
 PECO 
BGE(b)
 PHI 
Pepco(c)
 
DPL(c)
 ACE
June 30, 2019$61
 $5
 $—
 $48
 $8
 $5
 $3
 $—
September 30, 2019$59
 $4
 $—
 $47
 $8
 $5
 $3
 $—
December 31, 2018$65
 $8
 $—
 $49
 $8
 $5
 $3
 $—
$65
 $8
 $—
 $49
 $8
 $5
 $3
 $—
_________
(a)Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.
(b)BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.
(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.

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

Generation Regulatory Matters (Exelon and Generation)
Illinois Regulatory Matters
Zero Emission Standard. Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. During the first quarter of 2018, Generation recognized $150 million of revenue related to ZECs generated from June 1, 2017 through December 31, 2017.
On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. Both lawsuits argued that the Illinois ZEC program would distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices and sought a permanent injunction preventing the implementation of the program. The lawsuits were dismissed by the district court on July 14, 2017. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. On January 7, 2019, plaintiffs filed a petition seeking U.S. Supreme Court review of the case, which was denied on April 15, 2019.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Regulatory Matters

New Jersey Regulatory Matters
New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that will provide compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs.
On November 19, 2018, NJBPU issued an order providing for the method and application process for determining the eligibility of nuclear power plants, a draft method and process for ranking and selecting eligible nuclear power plants, and the establishment of a mechanism for each regulated utility to purchase ZECs from selected nuclear power plants. On December 19, 2018, PSEG filed complete applications seeking NJBPU approval for Salem 1 and Salem 2, of which Generation owns a 42.59% ownership interest, to participate in the ZEC program. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $10$21 million and $31 million for the three and sixnine months ended JuneSeptember 30, 2019. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. The appeal does not prevent implementation of the ZEC program. Exelon and Generation cannot predict the outcome of the appeal. See Note 8 — Early Plant Retirements for additional information related to Salem.
New York Regulatory Matters
New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC.
On October 19, 2016, a coalition of fossil-generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically, that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors, which was dismissed by the district court on July 25, 2017. On September 27, 2018, the U.S. Court of Appeals for the Second Circuit affirmed the lower court's dismissal of the complaint against the ZEC program. On January 7, 2019, the fossil-generation companies filed a petition seeking U.S. Supreme Court review of the case which was denied on April 15, 2019.
In addition, on November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. Subsequently, Generation, CENG and the NYPSC filed motions to dismiss the state court action, which were later opposed by the plaintiffs. On January 22,

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

2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. Generation, CENG andOn October 8, 2019, the state’s answers and briefs were filed on March 30, 2018. On December 17, 2018, plaintiffs filedcourt dismissed all remaining claims. The petitioners have until November 11, 2019 to file a reply brief introducing new arguments and new evidence. The Statenotice of New York filed a motion to strike on December 28, 2018. On January 4, 2019, Generation and CENG filed a motion to strike the new arguments and new evidence. The court must now decide whether or not to set the case for hearing.appeal.
See Note 8 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.
Federal Regulatory Matters
Operating License Renewals
Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) withfrom MDE for Conowingo, Generation continues to workhas been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.
On April 21, 2016, Generation and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a settlement agreement (DOI Settlement) resolving all fish passage issues between the parties.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Regulatory Matters


On April 27, 2018, the MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, unfavorable impact inon Exelon’s and Generation’s financial statements through an increase in capital expenditures and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous violatingand in violation of MDE regulations and state, federal, and constitutional law. Generation also requested that FERC defer the issuance of the federal license while these significant state and federal law issues are pending. On February 28, 2019, Generation filed a Petition for Declaratory Order with FERC requesting that FERC issue an order declaring that MDE waived its right to issue a 401 Certification for Conowingo because it failed to timely act on Conowingo's 401 Certification application and requesting that FERC decline to include the conditions proposedrequired by MDE in April 2018. Exelon also continues

On October 29, 2019, Generation and MDE entered into a settlement agreement (MDE Settlement) that would resolve all outstanding issues relating to challenge the 401 Certification throughCertification. Under the administrative process andMDE Settlement, the parties will propose license articles to FERC for approval as an offer of settlement to be incorporated by FERC into the new license in state and federal court. Exelonaccordance with FERC’s discretionary authority under the Federal Power Act. The MDE Settlement provides that if FERC approves the offer of settlement, MDE would waive its rights to issue a 401 Certification and Generation cannot predictwould agree to implement environmental protection, mitigation and enhancement measures over the final outcome or itsanticipated 50-year term of the new license. These measures address ecological and water quality matters, including modifications to river flows to improve aquatic habitat, along with other additional fish and eel passage improvements and initiatives to support rare, threatened and endangered wildlife, among other commitments. Exelon’s commitments under the DOI and MDE Settlements are not effective until incorporated by FERC into the new license.

The financial impact if any,of the DOI and MDE Settlements and other anticipated license commitments are estimated to be $11 million to $14 million per year, on Exelon or Generation.
average, recognized over the new license term, including capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license. As of JuneSeptember 30, 2019, $40$41 million of direct costs associated with Conowingo licensing efforts have been capitalized. See Note 4 — Regulatory MattersGeneration’s current depreciation provision for Conowingo assumes renewal of the Exelon 2018 Form 10-K for additional information on Generation's operating license renewal efforts.FERC license.
7. Impairment of Long-Lived AssetsAsset Impairments (Exelon and Generation)
The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying amountvalue of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. ChangesA variation in those inputsthe assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrants'Registrant's long-lived assets.
Equity Method Investments in Certain Distributed Energy Companies
In the third quarter of 2019, Generation’s equity method investments in certain distributed energy companies were fully impaired due to an other-than-temporary decline in market conditions and underperforming projects. Exelon and Generation recorded a pre-tax impairment charge of $164 million in Equity in losses of unconsolidated affiliates and an offsetting pre-tax $96 million in Net income attributable to noncontrolling interests in their Consolidated Statements of Operations and Comprehensive Income. As a result, Generation accelerated the amortization of investment tax credits associated with these companies and Exelon and Generation recorded a benefit of $46 million in Income taxes. The impairment charge and the accelerated amortization of investment tax credits resulted in a net $15 million decrease to Exelon’s and Generation’s earnings. See Note 2 — Variable Interest Entities for additional information.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 7 — Asset Impairments

Antelope Valley Solar Facility
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of JuneSeptember 30, 2019, Generation had approximately $740$730 million of net long-lived assets related to Antelope Valley. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and no impairment charge was recorded. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley’s net long-lived assets, which could be material.
Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,950$1,930 million of additional net long-lived assets as of JuneSeptember 30, 2019. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling interests. To date, there have been no indicators to suggest that the carrying amount of other net long-lived assets of EGR IV may not be recoverable.

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

Generation will continue to monitor the bankruptcy proceedings for any changes in circumstances that may indicate the carrying amount of the net long-lived assets of Antelope Valley or other long-lived assets of EGR IV may not be recoverable.
See Note 11 - Debt and Credit Agreements for additional information on the PG&E bankruptcy.
8. Early Plant Retirements (Exelon and Generation)
Exelon and Generation continuously evaluate factors that affect the current and expected economic value of Generation’s plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, just prior to its next scheduled nuclear refueling outage.
Nuclear Generation
In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York and Three Mile Island nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision makingdecision-making authority to retire Salem.
Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program and the New York CES, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Salem, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent the Illinois ZES, New Jersey ZEC program or the New York CES programs do not operate as expected over their full terms, each of these plants could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. See Note 6 — Regulatory Matters for additional information on the Illinois ZES, New Jersey ZEC program and 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 consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Generation announced that it would permanently cease generation operations at TMI on or aboutTMI. On September 30, 2019. Generation filed the required market and regulatory notifications to shut down the plant and PJM approved the deactivation. On April 5,20, 2019, Generation filed the PSDAR with the NRC detailing the plans for TMI after its final shutdown.permanently ceased generation operations at TMI.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Early Plant Retirements

On February 2, 2018, Generation announced that it would permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current operating cycle and permanently ceased generation operations inon September 17, 2018.

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

As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel, as well as operating and maintenance expenses. See Note 13 — Nuclear Decommissioning for additional information on changes to the nuclear decommissioning ARO balance. The total impact for the three and sixnine months ended JuneSeptember 30, 2019 and 2018 are summarized in the table below.
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
Income statement expense (pre-tax) 2019 2018 2019 2018 2019 2018 2019 2018
Depreciation and amortization(a)
                
Accelerated depreciation $71
 $152
 $145
 $289
 $71
 $152
 $216
 $441
Accelerated nuclear fuel amortization 4
 19
 9
 34
 3
 18
 13
 52
Operating and maintenance(b)
 —
 2
 (83) 28
 39
 4
 (44) 32
Total $75
 $173
 $71
 $351
 $113
 $174
 $185
 $525
_________
(a)Reflects incremental accelerated depreciation and amortization for TMI for the three and sixnine months ended JuneSeptember 30, 2019. Reflects incremental accelerated depreciation for TMI and Oyster Creek for the three and sixnine months ended JuneSeptember 30, 2018. The Oyster Creek amounts are from February 2, 2018 through June 30,September 17, 2018. The TMI amounts are through September 20, 2019.
(b)In 2019, primarily reflects decrease to estimated decommissioning costs for TMI.the net impacts associated with the remeasurements of the TMI ARO in the first and third quarters. See Note 13 — Nuclear Decommissioning for additional information on the first quarter 2019 TMI ARO update. In 2018, primarily reflects materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments associated with the early retirement decisions for TMI and Oyster Creek. Excludes the charges in the third quarter of 2018 and second quarter of 2019 to Operating and maintenance expense for the ARO remeasurement due to the sale of Oyster Creek. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.
Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.
Other Generation
On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets absent regulatory reforms on June 1, 2022, at the end of the then-current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 was then committed through May 2021.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. Those adjustments were reflected in a compliance filing filed March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. Initial briefs in the ROE proceeding were filed on April 19, 2019 and reply briefs were filed on July 18, 2019. On January 4, 2019, Generation notified ISO-NE that it will participate in the Forward Capacity Market auction for the 2022 - 2023 capacity commitment period. In addition, on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 order, which does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022-2023 capacity commitment period. On June 10, 2019, ISO-NE announced that it has determined that Mystic 8 and 9 are needed for fuel security for the 2023-2024 capacity commitment period.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Early Plant Retirements

On March 25, 2019, ISO-NE filed the Inventoried Energy Program, which is intended to provide an interim fuel security program pending conclusion of the stakeholder process to develop a long-term, market-based solution to address fuel security. Exelon filed comments on the Inventoried Energy Program proposal on April 15, 2019. FERC has ordered ISO-NE to file long-term, market-based fuel security rules by October 15, 2019. On May 8, 2019, FERC issued a deficiency letter to ISO-NE seeking additional information on the Inventoried Energy Program proposal,

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

and ISO-NE filed a response on June 6, 2019. On July 15,August 5, 2019, FERC held a staff-led public meeting onallowed the Inventoried Energy Program to take effect by operation of law. Several parties have filed requests for rehearing. FERC ordered ISO-NE to file long-term, market-based fuel security rules by October 15, 2019. On August 30, 2019, FERC granted an extension of time to file the long-term, market-based fuel security proposal.rules to April 15, 2020.
The following table provides the balance sheet amounts as of JuneSeptember 30, 2019 for Exelon's and Generation’s significant assets and liabilities associated with the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by a decisionthe failure to permanently cease generation operations in the absence ofadopt long-term market rule changes.solutions for reliability and fuel security.
 June 30, 2019 September 30, 2019
Asset Balances    
Materials and supplies inventory $30
 $31
Fuel inventory 11
 5
Completed plant, net 896
 889
Construction work in progress 4
 7
Liability Balances    
Asset retirement obligation (1) (2)

9. Fair Value of Financial Assets and Liabilities (All Registrants)
Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
Level 2 - inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
Level 3 - unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 11 — Fair Value of Financial Assets and Liabilities of the Exelon 2018 Form 10-K, unless otherwise noted below.
Fair Value of Financial Liabilities Recorded at Amortized Cost
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of JuneSeptember 30, 2019 and December 31, 2018. The Registrants have no financial liabilities classified as Level 1.
The carrying amounts of the Registrants’ short-term liabilities as presented on their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.

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

Note 9 — Fair Value of Financial Assets and Liabilities

 June 30, 2019 December 31, 2018 September 30, 2019 December 31, 2018
 Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value Carrying Amount Fair Value
 Level 2 Level 3 Total Level 2 Level 3 Total Level 2 Level 3 Total Level 2 Level 3 Total
Long-Term Debt, including amounts due within one year(a)

Long-Term Debt, including amounts due within one year(a)

Long-Term Debt, including amounts due within one year(a)

Exelon $35,685
 $36,248
 $2,569
 $38,817
 $35,424
 $33,711
 $2,158
 $35,869
 $36,304
 $38,056
 $2,541
 $40,597
 $35,424
 $33,711
 $2,158
 $35,869
Generation 8,704
 7,822
 1,472
 9,294
 8,793
 7,467
 1,443
 8,910
 8,613
 7,962
 1,398
 9,360
 8,793
 7,467
 1,443
 8,910
ComEd 8,195
 9,222
 —
 9,222
 8,101
 8,390
 —
 8,390
 8,196
 9,622
 —
 9,622
 8,101
 8,390
 —
 8,390
PECO 3,085
 3,415
 50
 3,465
 3,084
 3,157
 50
 3,207
 3,404
 3,891
 50
 3,941
 3,084
 3,157
 50
 3,207
BGE 2,877
 3,197
 —
 3,197
 2,876
 2,950
 —
 2,950
 3,270
 3,678
 —
 3,678
 2,876
 2,950
 —
 2,950
PHI 6,509
 5,823
 1,047
 6,870
 6,259
 5,436
 665
 6,101
 6,494
 5,993
 1,093
 7,086
 6,259
 5,436
 665
 6,101
Pepco 2,860
 3,134
 377
 3,511
 2,719
 2,901
 196
 3,097
 2,860
 3,249
 395
 3,644
 2,719
 2,901
 196
 3,097
DPL 1,495
 1,396
 218
 1,614
 1,494
 1,303
 193
 1,496
 1,495
 1,437
 232
 1,669
 1,494
 1,303
 193
 1,496
ACE 1,329
 1,025
 451
 1,476
 1,188
 987
 275
 1,262
 1,324
 1,034
 466
 1,500
 1,188
 987
 275
 1,262
Long-Term Debt to Financing Trusts(a)

Long-Term Debt to Financing Trusts(a)

Long-Term Debt to Financing Trusts(a)

Exelon $390
 $—
 $415
 $415
 $390
 $—
 $400
 $400
 $390
 $—
 $426
 $426
 $390
 $—
 $400
 $400
ComEd 205
 —
 209
 209
 205
 —
 209
 209
 205
 —
 223
 223
 205
 —
 209
 209
PECO 184
 —
 206
 206
 184
 —
 191
 191
 184
 —
 203
 203
 184
 —
 191
 191
SNF Obligation
Exelon $1,186
 $1,025
 $—
 $1,025
 $1,171
 $949
 $—
 $949
 $1,193
 $1,017
 $—
 $1,017
 $1,171
 $949
 $—
 $949
Generation 1,186
 1,025
 —
 1,025
 1,171
 949
 —
 949
 1,193
 1,017
 —
 1,017
 1,171
 949
 —
 949
____
(a)Includes unamortized debt issuance costs which are not fair valued.
Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of JuneSeptember 30, 2019 and December 31, 2018:
Exelon and Generation
Exelon GenerationExelon Generation
As of June 30, 2019Level 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, 2019Level 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)
$648
 $—
 $—
 $—
 $648
 $323
 $—
 $—
 $—
 $323
$1,719
 $—
 $—
 $—
 $1,719
 $896
 $—
 $—
 $—
 $896
NDT fund investments        
         
        
         
Cash equivalents(b)
1,241
 90
 —
 —
 1,331
 1,241
 90
 —
 —
 1,331
315
 78
 —
 —
 393
 315
 78
 —
 —
 393
Equities3,123
 1,638
 —

1,328
 6,089
 3,123
 1,638
 —

1,328
 6,089
3,121
 1,727
 —

1,314
 6,162
 3,121
 1,727
 —

1,314
 6,162
Fixed income                                      
Corporate debt—
 1,453
 247
 —
 1,700
 —
 1,453
 247
 —
 1,700
—
 1,473
 259
 —
 1,732
 —
 1,473
 259
 —
 1,732
U.S. Treasury and agencies1,589
 134
 —
 —
 1,723
 1,589
 134
 —
 —
 1,723
1,777
 152
 —
 —
 1,929
 1,777
 152
 —
 —
 1,929
Foreign governments—
 58
 —
 —
 58
 —
 58
 —
 —
 58
—
 56
 —
 —
 56
 —
 56
 —
 —
 56
State and municipal debt—
 81
 —
 —
 81
 —
 81
 —
 —
 81
—
 85
 —
 —
 85
 —
 85
 —
 —
 85
Other(c)
—
 19
 —
 955
 974
 —
 19
 —
 955
 974
—
 23
 —
 979
 1,002
 —
 23
 —
 979
 1,002
Fixed income subtotal1,589

1,745

247
 955

4,536

1,589

1,745

247
 955

4,536
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — Fair Value of Financial Assets and Liabilities

Exelon GenerationExelon Generation
As of June 30, 2019Level 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, 2019Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
Fixed income subtotal1,777

1,789

259
 979

4,804

1,777

1,789

259
 979

4,804
Middle market lending—
 —
 292
 455
 747
 —
 —
 292
 455
 747
—
 —
 255
 445
 700
 —
 —
 255
 445
 700
Private equity—
 —
 —
 379
 379
 —
 —
 —
 379
 379
—
 —
 —
 398
 398
 —
 —
 —
 398
 398
Real estate—
 —
 —
 557
 557
 —
 —
 —
 557
 557
—
 —
 —
 581
 581
 —
 —
 —
 581
 581
NDT fund investments subtotal(d)
5,953

3,473

539
 3,674

13,639

5,953

3,473

539
 3,674

13,639
5,213

3,594

514
 3,717

13,038

5,213

3,594

514
 3,717

13,038
Rabbi trust investments        
         
        
         
Cash equivalents49
 —
 —
 —
 49
 4
 —
 —
 —
 4
49
 —
 —
 —
 49
 4
 —
 —
 —
 4
Mutual funds73
 —
 —
 —
 73
 23
 —
 —
 —
 23
77
 —
 —
 —
 77
 24
 —
 —
 —
 24
Fixed income—
 13
 —
 —
 13
 —
 —
 —
 —
 —
—
 13
 —
 —
 13
 —
 —
 —
 —
 —
Life insurance contracts—
 72
 40
 —
 112
 —
 23
 —
 —
 23
—
 76
 40
 —
 116
 —
 24
 —
 —
 24
Rabbi trust investments subtotal122

85

40
 —

247

27

23

—
 —

50
126

89

40
 —

255

28

24

—
 —

52
Commodity derivative assets                                      
Economic hedges505
 2,148
 1,875
 —
 4,528
 505
 2,148
 1,875
 —
 4,528
533
 1,488
 1,817
 —
 3,838
 533
 1,488
 1,817
 —
 3,838
Proprietary trading—
 44
 139
 —
 183
 —
 44
 139
 —
 183
—
 54
 156
 —
 210
 —
 54
 156
 —
 210
Effect of netting and allocation of collateral(e)(f)
(646) (2,042) (965) —
 (3,653) (646) (2,042) (965) —
 (3,653)(677) (1,261) (1,025) —
 (2,963) (677) (1,261) (1,025) —
 (2,963)
Commodity derivative assets subtotal(141)
150

1,049
 —

1,058

(141)
150

1,049
 —

1,058
(144)
281

948
 —

1,085

(144)
281

948
 —

1,085
Total assets6,582

3,708

1,628

3,674

15,592

6,162

3,646

1,588

3,674

15,070
6,914

3,964

1,502

3,717

16,097

5,993

3,899

1,462

3,717

15,071
Liabilities                                      
Commodity derivative liabilities                                      
Economic hedges(743) (2,539) (1,606) —
 (4,888) (743) (2,539) (1,333) —
 (4,615)(773) (1,695) (1,686) —
 (4,154) (773) (1,695) (1,406) —
 (3,874)
Proprietary trading—
 (44) (71) —
 (115) —
 (44) (71) —
 (115)—
 (59) (89) —
 (148) —
 (59) (89) —
 (148)
Effect of netting and allocation of collateral(e)(f)
743
 2,438
 1,228
 —
 4,409
 743
 2,438
 1,228
 —
 4,409
770
 1,585
 1,329
 —
 3,684
 770
 1,585
 1,329
 —
 3,684
Commodity derivative liabilities subtotal—
 (145) (449) —
 (594) —
 (145) (176) —
 (321)(3) (169) (446) —
 (618) (3) (169) (166) —
 (338)
Deferred compensation obligation—
 (137) —
 —
 (137) —
 (36) —
 —
 (36)—
 (140) —
 —
 (140) —
 (37) —
 —
 (37)
Total liabilities—

(282)
(449) —

(731)
—

(181)
(176) —

(357)(3)
(309)
(446) —

(758)
(3)
(206)
(166) —

(375)
Total net assets$6,582

$3,426

$1,179
 $3,674

$14,861

$6,162

$3,465

$1,412
 $3,674

$14,713
$6,911

$3,655

$1,056
 $3,717

$15,339

$5,990

$3,693

$1,296
 $3,717

$14,696
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — Fair Value of Financial Assets and Liabilities

 Exelon Generation
As of December 31, 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)
$1,243
 $—
 $—
 $—
 $1,243
 $581
 $—
 $—
 $—
 $581
NDT fund investments                  

Cash equivalents(b)
252
 86
 —
 —
 338
 252
 86
 —
 —
 338
Equities2,918

1,591

—

1,381

5,890

2,918

1,591

—

1,381

5,890
Fixed income                   
Corporate debt—
 1,593
 230
 —
 1,823
 —
 1,593
 230
 —
 1,823
U.S. Treasury and agencies2,081
 99
 —
 —
 2,180
 2,081
 99
 —
 —
 2,180
Foreign governments—
 50
 —
 —
 50
 —
 50
 —
 —
 50
State and municipal debt—
 149
 —
 —
 149
 —
 149
 —
 —
 149
Other(c)
—
 30
 —
 846
 876
 —
 30
 —
 846
 876
Fixed income subtotal2,081

1,921

230
 846

5,078

2,081

1,921

230
 846

5,078
Middle market lending—
 —
 313
 367
 680
 —
 —
 313
 367
 680
Private equity—
 —
 —
 329
 329
 —
 —
 —
 329
 329
Real estate—
 —
 —
 510
 510
 —
 —
 —
 510
 510
NDT fund investments subtotal(d)
5,251

3,598

543
 3,433

12,825

5,251

3,598

543
 3,433
 12,825
Rabbi trust investments                   
Cash equivalents48
 —
 —
 —
 48
 5
 —
 —
 —
 5
Mutual funds72
 —
 —
 —
 72
 24
 —
 —
 —
 24
Fixed income—
 15
 —
 —
 15
 —
 —
 —
 —
 —
Life insurance contracts—
 70
 38
 —
 108
 —
 22
 —
 —
 22
Rabbi trust investments subtotal120

85

38
 —

243

29

22

—
 —

51
Commodity derivative assets                   
Economic hedges541
 2,760
 1,470
 —
 4,771
 541
 2,760
 1,470
 —
 4,771
Proprietary trading—
 69
 77
 —
 146
 —
 69
 77
 —
 146
Effect of netting and allocation of collateral(e)(f)
(582) (2,357) (732) —
 (3,671) (582) (2,357) (732) —
 (3,671)
Commodity derivative assets subtotal(41)
472

815
 —

1,246

(41)
472

815
 —

1,246
Total assets6,573

4,155

1,396

3,433

15,557

5,820

4,092

1,358

3,433

14,703

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

Note 9 — Fair Value of Financial Assets and Liabilities

 Exelon Generation
As of December 31, 2018Level 1 Level 2 Level 3 Not subject to leveling Total Level 1
Level 2
Level 3 Not subject to leveling
Total
Liabilities        
         
Commodity derivative liabilities                   
Economic hedges(642) (2,963) (1,276) —
 (4,881) (642) (2,963) (1,027) —
 (4,632)
Proprietary trading—
 (73) (21) —
 (94) —
 (73) (21) —
 (94)
Effect of netting and allocation of collateral(e)(f)
639
 2,581
 808
 —
 4,028
 639
 2,581
 808
 —
 4,028
Commodity derivative liabilities subtotal(3)
(455)
(489) —

(947)
(3)
(455)
(240) —

(698)
Deferred compensation obligation—
 (137) —
 —
 (137) —
 (35) —
 —
 (35)
Total liabilities(3)
(592)
(489) —

(1,084)
(3)
(490)
(240) —

(733)
Total net assets$6,570

$3,563

$907
 $3,433

$14,473

$5,817

$3,602

$1,118
 $3,433

$13,970
_________
(a)Exelon excludes cash of $447$347 million and $458 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, and restricted cash of $83$112 million and $80 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $191$186 million and $185 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $329$183 million and $283 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, and restricted cash of $45$66 million and $39 million at JuneSeptember 30, 2019 and December 31, 2018, respectively. 
(b)Includes $75$85 million and $50 million of cash received from outstanding repurchase agreements at JuneSeptember 30, 2019 and December 31, 2018, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.
(c)Includes a derivative liability of $2 million and a derivative asset of $44 million, which have total notional amounts of $827$864 million and $1,432 million at JuneSeptember 30, 2019 and December 31, 2018, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of Exelon and Generation's exposure to credit or market loss.
(d)Excludes net liabilities of $141$176 million and $130 million at JuneSeptember 30, 2019 and December 31, 2018, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.
(e)Collateral posted/(received) from counterparties totaled $97$93 million, $396$324 million and $263$304 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of JuneSeptember 30, 2019. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $57 million, $224 million and $76 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2018.
(f)Of the collateral posted/(received), $358$306 million and $(94) million represents variation margin on the exchanges as of JuneSeptember 30, 2019 and December 31, 2018, respectively.
As of JuneSeptember 30, 2019, Exelon and Generation have outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $121$93 million, $84$241 million, $396$383 million, and $252$388 million, respectively. These commitments will be funded by Generation’s existing NDT funds.
Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $75 million as of JuneSeptember 30, 2019. Changes were immaterial in fair value, cumulative adjustments and impairments for the three and sixnine months ended JuneSeptember 30, 2019.
Valuation Techniques Used to Determine Net Asset Value
Certain NDT Fund Investments are not classified within the fair value hierarchy and are included under the heading “Not subject to leveling” in the table above. These investments are measured at fair value using NAV per share as a practical expedient and include commingled funds, mutual funds which are not publicly quoted, managed middle market funds, private equity and real estate funds.

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

Note 9 — Fair Value of Financial Assets and Liabilities

For commingled funds and mutual funds, which are not publicly quoted, the fair value is primarily derived from the quoted prices in active markets on the underlying securities and can typically be redeemed monthly with 30 or less days of notice and without further restrictions. For managed middle market funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. 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. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon’s understanding of the investment funds. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.
ComEd, PECO and BGE
ComEd PECO BGEComEd PECO BGE
As of June 30, 2019Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
As of September 30, 2019Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets                                              
Cash equivalents(a)
$222
 $—
 $—
 $222
 $9
 $—
 $—
 $9
 $1
 $—
 $—
 $1
$264
 $—
 $—
 $264
 $207
 $—
 $—
 $207
 $122
 $—
 $—
 $122
Rabbi trust investments      
       
       
      
       
       
Mutual funds—
 —
 —
 —
 7
 —
 —
 7
 7
 —
 —
 7
—
 —
 —
 —
 8
 —
 —
 8
 7
 —
 —
 7
Life insurance contracts—
 —
 —
 —
 —
 10
 —
 10
 —
 —
 —
 —
—
 —
 —
 —
 —
 11
 —
 11
 —
 —
 —
 —
Rabbi trust investments subtotal—

—

—

—

7

10

—

17

7

—

—

7
—

—

—

—

8

11

—

19

7

—

—

7
Total assets222

—

—

222

16

10

—

26

8

—

—

8
264

—

—

264

215

11

—

226

129

—

—

129
Liabilities      
       
       
      
       
       
Deferred compensation obligation—
 (7) —
 (7) —
 (8) —
 (8) —
 (5) —
 (5)—
 (7) —
 (7) —
 (8) —
 (8) —
 (5) —
 (5)
Mark-to-market derivative liabilities(b)
—
 —
 (273) (273) —
 —
 —
 —
 —
 —
 —
 —
—
 —
 (280) (280) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (7) (273) (280) —
 (8) —
 (8) —
 (5) —
 (5)—
 (7) (280) (287) —
 (8) —
 (8) —
 (5) —
 (5)
Total net assets (liabilities)$222
 $(7) $(273) $(58) $16
 $2
 $—
 $18
 $8
 $(5) $—
 $3
$264
 $(7) $(280) $(23) $215
 $3
 $—
 $218
 $129
 $(5) $—
 $124
 ComEd PECO BGE
As of December 31, 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)
$209
 $—
 $—
 $209
 $111
 $—
 $—
 $111
 $4
 $—
 $—
 $4
Rabbi trust investments      
       
       
Mutual funds—
 —
 —
 —
 7
 —
 —
 7
 6
 —
 —
 6
Life insurance contracts—
 —
 —
 —
 —
 10
 —
 10
 —
 —
 —
 —
Rabbi trust investments subtotal—

—

—

—

7

10

—

17

6

—

—

6
Total assets209

—

—

209

118

10

—

128

10

—

—

10
Liabilities      
       
       
Deferred compensation obligation—
 (6) —
 (6) —
 (10) —
 (10) —
 (5) —
 (5)
Mark-to-market derivative liabilities(b)
—
 —
 (249) (249) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (6) (249) (255) —
 (10) —
 (10) —
 (5) —
 (5)
Total net assets (liabilities)$209
 $(6) $(249) $(46) $118
 $—
 $—
 $118
 $10
 $(5) $—
 $5

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

Note 9 — Fair Value of Financial Assets and Liabilities

_________
(a)ComEd excludes cash of $65$76 million and $93 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, and restricted cash of $29$31 million and $28 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $174$171 million and $166 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  PECO excludes cash of $17$23 million and $24 million at JuneSeptember 30, 2019 and December 31, 2018, respectively.  BGE excludes cash of $8 million and $7 million at both JuneSeptember 30, 2019 and December 31, 2018, respectively, and restricted cash of $1 million and $2 million at JuneSeptember 30, 2019 and December 31, 2018, respectively.
(b)The Level 3 balance consists of the current and noncurrent liability of $29$27 million and $244$253 million, respectively, at JuneSeptember 30, 2019, and $26 million and $223 million, respectively, at December 31, 2018, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
PHI, Pepco, DPL and ACE
As of June 30, 2019 As of December 31, 2018As of September 30, 2019 As of December 31, 2018
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)
$87
 $—
 $—
 $87
 $147
 $—
 $—
 $147
$107
 $—
 $—
 $107
 $147
 $—
 $—
 $147
Rabbi trust investments      
       
      
       
Cash equivalents44
 —
 —
 44
 42
 —
 —
 42
43
 —
 —
 43
 42
 —
 —
 42
Mutual funds13
 —
 —
 13
 13
 —
 —
 13
13
 —
 —
 13
 13
 —
 —
 13
Fixed income—
 13
 —
 13
 —
 15
 —
 15
—
 13
 —
 13
 —
 15
 —
 15
Life insurance contracts—
 23
 40
 63
 —
 22
 38
 60
—
 24
 40
 64
 —
 22
 38
 60
Rabbi trust investments subtotal57

36

40

133

55

37

38

130
56

37

40

133

55

37

38

130
Total assets144

36

40

220
 202

37

38

277
163

37

40

240
 202

37

38

277
Liabilities      
       
      
       
Deferred compensation obligation—
 (19) —
 (19) —
 (21) —
 (21)—
 (19) —
 (19) —
 (21) —
 (21)
Total liabilities—

(19)
—

(19)
—

(21)
—

(21)—

(19)
—

(19)
—

(21)
—

(21)
Total net assets$144

$17

$40

$201
 $202

$16

$38

$256
$163

$18

$40

$221
 $202

$16

$38

$256
Pepco DPL ACEPepco DPL ACE
As of June 30, 2019Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
As of September 30, 2019Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
 
 
 
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 
 
 
Cash equivalents(a)
$40
 $—
 $—
 $40
 $1
 $—
 $—
 $1
 $19
 $—
 $—
 $19
$34
 $—
 $—
 $34
 $—
 $—
 $—
 $—
 $18
 $—
 $—
 $18
Rabbi trust investments                                              
Cash equivalents43
 —
 —
 43
 —
 —
 —
 —
 —
 —
 —
 —
43
 —
 —
 43
 —
 —
 —
 —
 —
 —
 —
 —
Fixed income—
 3
 —
 3
 —
 —
 —
 —
 —
 —
 —
 —
—
 3
 —
 3
 —
 —
 —
 —
 —
 —
 —
 —
Life insurance contracts—
 23
 39
 62
 —
 —
 —
 —
 —
 —
 —
 —
—
 24
 40
 64
 —
 —
 —
 —
 —
 —
 —
 —
Rabbi trust investments subtotal43

26

39

108

—

—

—

—

—

—

—

—
43

27

40

110

—

—

—

—

—

—

—

—
Total assets83

26

39

148

1

—

—

1

19

—

—

19
77

27

40

144

—

—

—

—

18

—

—

18
Liabilities
 
 
 

 
 
 
 
 
 
 
 

 
 
 

 
 
 
 
 
 
 
 
Deferred compensation obligation—
 (2) —
 (2) —
 —
 —
 —
 —
 —
 —
 —
—
 (2) —
 (2) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—

(2)
—

(2)
—

—

—

—

—

—

—

—
—

(2)
—

(2)
—

—

—

—

—

—

—

—
Total net assets$83
 $24
 $39
 $146
 $1
 $—
 $—
 $1
 $19
 $—
 $—
 $19
$77
 $25
 $40
 $142
 $—
 $—
 $—
 $—
 $18
 $—
 $—
 $18
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — Fair Value of Financial Assets and Liabilities


Pepco DPL ACE
As of December 31, 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)
$38
 $—
 $—
 $38
 $16
 $—
 $—
 $16
 $23
 $—
 $—
 $23
Rabbi trust investments                       
Cash equivalents41
 —
 —
 41
 —
 —
 —
 —
 —
 —
 —
 —
Fixed income—
 5
 —
 5
 —
 —
 —
 —
 —
 —
 —
 —
Life insurance contracts—
 22
 37
 59
 —
 —
 —
 —
 —
 —
 —
 —
Rabbi trust investments subtotal41

27

37

105

—

—

—

—

—

—

—

—
Total assets79

27

37

143

16

—

—

16

23

—

—

23
Liabilities                       
Deferred compensation obligation—
 (3) —
 (3) —
 (1) —
 (1) —
 —
 —
 —
Total liabilities—
 (3) —
 (3) —
 (1) —
 (1) —
 —
 —
 —
Total net assets (liabilities)$79
 $24
 $37

$140
 $16
 $(1) $—
 $15
 $23
 $—
 $—
 $23
_________
(a)PHI excludes cash of $21$45 million and $39 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $17$15 million and $19 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  Pepco excludes cash of $12$18 million and $15 million at JuneSeptember 30, 2019 and December 31, 2018, respectively. DPL excludes cash of $3$11 million and $8 million at JuneSeptember 30, 2019 and December 31, 2018, respectively. ACE excludes cash of $4$13 million and $7 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $17$15 million and $19 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
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 sixnine months ended JuneSeptember 30, 2019 and 2018:
Exelon Generation ComEd PHI and Pepco  Exelon Generation ComEd PHI and Pepco  
Three Months Ended June 30, 2019Total 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation
Balance as of March 31, 2019$838
 $540
 $499
 $1,039
 $(240) $39
 $—
Three Months Ended September 30, 2019Total 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation
Balance as of June 30, 2019$1,179
 $539
 $873
 $1,412
 $(273) $40
 $—
Total realized / unrealized gains (losses)
     
      
     
      
Included in net income275
 2
 272
(a) 
274
 —
 1
 —
(171) 2
 (173)
(a) 
(171) —
 —
 —
Included in noncurrent payables to affiliates—
 10
 —
 10
 —
 —
 (10)—
 11
 —
 11
 —
 —
 (11)
Included in regulatory assets/liabilities(23) —
 —
 —
 (33)
(b) 
—
 10
4
 —
 —
 —
 (7)
(b) 
—
 11
Change in collateral106
 —
 106
 106
 —
 —
 —
41
 —
 41
 41
 —
 —
 —
Purchases, sales, issuances and settlements

     
      

     
      
Purchases51
 40
 11
 51
 —
 —
 —
53
 1
 52
 53
 —
 —
 —
Sales(1) —
 (1) (1) —
 —
 —
(22) (21) (1) (22) —
 —
 —
Settlements(53) (53) —
 (53) —
 —
 —
(18) (18) —
 (18) —
 —
 —
Transfers into Level 33
 —
 3
(c) 
3
 —
 —
 —
1
 —
 1
(c) 
1
 —
 —
 —
Transfers out of Level 3(17) —
 (17)
(c) 
(17) —
 —
 —
(11) —
 (11)
(c) 
(11) —
 —
 —
Balance at June 30, 2019$1,179
 $539
 $873
 $1,412
 $(273) $40
 $—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2019$339
 $1
 $337
 $338
 $—
 $1
 $—
Balance at September 30, 2019$1,056
 $514
 $782
 $1,296
 $(280) $40
 $—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2019$(18) $2
 $(20) $(18) $—
 $—
 $—
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — Fair Value of Financial Assets and Liabilities

Exelon Generation ComEd PHI and Pepco  Exelon Generation ComEd PHI and Pepco  
Six Months Ended June 30, 2019Total 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation
Nine Months Ended September 30, 2019Total 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation
Balance as of December 31, 2018$907
 $543
 $575
 $1,118
 $(249) $38
 $—
$907
 $543
 $575
 $1,118
 $(249) $38
 $—
Total realized / unrealized gains (losses)

     

      

     

      
Included in net income46
 3
 41
(a) 
44
 —
 2
 —
(125) 5
 (132)
(a) 
(127) —
 2
 —
Included in noncurrent payables to affiliates—
 21
 —
 21
 —
 —
 (21)—
 32
 —
 32
 —
 —
 (32)
Included in regulatory assets(3) —
 —
 —
 (24)
(b) 
—
 21
1
 —
 —
 —
 (31)
(b) 
—
 32
Change in collateral187
 —
 187
 187
 —
 —
 —
227
 —
 227
 227
 —
 —
 —
Purchases, sales, issuances and settlements

     

      

     

      
Purchases110
 42
 68
 110
 —
 —
 —
163
 43
 120
 163
 —
 —
 —
Sales(1) —
 (1) (1) —
 —
 —
(23) (21) (2) (23) —
 —
 —
Settlements(70) (70) —
 (70) —
 —
 —
(88) (88) —
 (88) —
 —
 —
Transfers into Level 33
 —
 3
(c) 
3
 —
 —
 —
5
 —
 5
(c) 
5
 —
 —
 —
Transfers out of Level 3—
 —
 —
(c) 
—
 —
 —
 —
(11) —
 (11)
(c) 
(11) —
 —
 —
Balance as of June 30, 2019$1,179
 $539
 $873
 $1,412
 $(273) $40
 $—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2019$191
 $3
 $186
 $189
 $—
 $2
 $—
Balance as of September 30, 2019$1,056
 $514
 $782
 $1,296
 $(280) $40
 $—
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, 2019$173
 $5
 $166
 $171
 $—
 $2
 $—

__________
(a)
Includes a reduction for the reclassification of $65$153 million and $145298 million of realized gains due to the settlement of derivative contracts for the three and sixnine months ended JuneSeptember 30, 2019, respectively.
(b)Includes $41$7 million of decreases in fair value and an increase for realized losses due to settlements of $8$4 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended JuneSeptember 30, 2019. Includes $37$31 million of increasesdecreases in fair value and an increase for realized losses due to settlements of $13$17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the sixnine months ended JuneSeptember 30, 2019.
(c)Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.

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

Note 9 — Fair Value of Financial Assets and Liabilities

Exelon Generation ComEd PHI and Pepco  Exelon Generation ComEd PHI and Pepco  
Three Months Ended June 30, 2018Total 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation
Balance as of March 31, 2018$1,283
 $609
 $918
 $1,527
 $(267) $23
 $—
Three Months Ended September 30, 2018Total 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts��Eliminated in Consolidation
Balance as of June 30, 2018$1,106
 $585
 $737
 $1,322
 $(252) $36
 $—
Total realized / unrealized gains (losses)      

            

      
Included in net income(112) —
 (113)
(a) 
(113) —
 1
 —
(259) (1) (259)
(a) 
(260) —
 1
 —
Included in noncurrent payables to affiliates—
 (3) —
 (3) —
 —
 3
—
 (4) —
 (4) —
 —
 4
Included in regulatory assets12
 —
 —
 —
 15
(b) 
—
 (3)(11) —
 —
 —
 (7)
(b) 
—
 (4)
Change in collateral(49) —
 (49) (49) —
 —
 —
(44) —
 (44) (44) —
 —
 —
Purchases, sales, issuances and settlements
     

      
     

      
Purchases30
 17
 13
 30
 —
 —
 —
96
 15
 81
 96
 —
 —
 —
Sales(1) —
 (1) (1) —
 —
 —
Settlements(26) (38) —
 (38) —
 12
 —
(29) (29) —
 (29) —
 —
 —
Transfers into Level 3(15) —
 (15)
(c) 
(15) —
 —
 —
3
 —
 3
(c) 
3
 —
 —
 —
Transfers out of Level 3(16) —
 (16)
(c) 
(16) —
 —
 —
(6) —
 (6)
(c) 
(6) —
 —
 —
Balance as of June 30, 2018$1,106
 $585

$737

$1,322

$(252)
$36
 $—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2018$3
 $(4) $7
 $3
 $—
 $—
 $—
Balance as of September 30, 2018$856
 $566

$512

$1,078

$(259)
$37
 $—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2018$(105) $(1) $(104) $(105) $—
 $—
 $—

Exelon Generation ComEd PHI and Pepco  Exelon Generation ComEd PHI and Pepco  
Six Months Ended June 30, 2018Total 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation
Nine Months Ended September 30, 2018Total 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation
Balance as of December 31, 2017$966
 $648
 $552
 $1,200
 $(256) $22
 $—
$966
 $648
 $552
 $1,200
 $(256) $22
 $—
Total realized / unrealized gains (losses)
     

      
     

      
Included in net income74
 1
 71
(a) 
72
 —
 2
 —
(186) (1) (188)
(a) 
(189) —
 3
 —
Included in noncurrent payables to affiliates—
 3
 —
 3
 —
 —
 (3)
Included in regulatory assets7
 —
 —
 —
 4
(b) 
—
 3
(3) —
 —
 —
 (3)
(b) 
—
 —
Change in collateral57
 —
 57
 57
 —
 —
 —
14
 —
 14
 14
 —
 —
 —
Purchases, sales, issuances and settlements
     

      
     

      
Purchases119
 19
 100
 119
 —
 —
 —
215
 34
 181
 215
 —
 —
 —
Sales(4) —
 (4) (4) —
 —
 —
(3) —
 (3) (3) —
 —
 —
Settlements(74) (86) —
 (86) —
 12
 —
(103) (115) —
 (115) —
 12
 —
Transfers into Level 3(23) —
 (23)
(c) 
(23) —
 —
 —
(21) —
 (21)
(c) 
(21) —
 —
 —
Transfers out of Level 3(16) —
 (16)
(c) 
(16) —
 —
 —
(23) —
 (23)
(c) 
(23) —
 —
 —
Balance as of June 30, 2018$1,106
 $585
 $737
 $1,322

$(252) $36
 $—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2018$259
 $(4) $263
 $259
 $—
 $—
 $—
Balance as of September 30, 2018$856
 $566
 $512
 $1,078

$(259) $37
 $—
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$154
 $(5) $159
 $154
 $—
 $—
 $—


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

__________
(a)Includes a reduction for the reclassification of $120$155 million and $192$347 million of realized gainslosses due to the settlement of derivative contracts for the three and sixnine months ended JuneSeptember 30, 2018, respectively.
(b)
Includes $114 million of decreasesincreases in fair value and an increase for realized losses due to settlements of $4$3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended JuneSeptember 30, 2018. Includes $6$9 million of increasesdecreases in fair value and an increase for realized losses due to settlements of $10$12 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the sixnine months ended JuneSeptember 30, 2018.
(c)Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — Fair Value of Financial Assets and Liabilities

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 sixnine months ended JuneSeptember 30, 2019 and 2018:
 Exelon Generation PHI and Pepco
 Operating
Revenues		 Purchased
Power and
Fuel		 Operating and Maintenance Other, net Operating
Revenues		 Purchased
Power and
Fuel		 Other, net Operating and Maintenance
Total realized gains (losses) for the three months ended June 30, 2019$275
 $(3) $1
 $2
 $275
 $(3) $2
 $1
Total realized (losses) gains for the six months ended June 30, 2019147
 (106) 2
 3
 147
 (106) 3
 2
Total unrealized gains (losses) for the three months ended June 30, 2019360
 (23) 1
 1
 360
 (23) 1
 1
Total unrealized gains (losses) for the six months ended June 30, 2019269
 (83) 2
 3
 269
 (83) 3
 2
 Exelon Generation PHI and Pepco
 Operating
Revenues		 Purchased
Power and
Fuel		 Operating and Maintenance Other, net Operating
Revenues		 Purchased
Power and
Fuel		 Other, net Operating and Maintenance
Total realized (losses) gains for the three months ended September 30, 2019$(25) $(148) $—
 $2
 $(25) $(148) $2
 $—
Total realized gains (losses) for the nine months ended September 30, 2019122
 (254) —
 5
 122
 (254) 5
 —
Total unrealized gains (losses) for the three months ended September 30, 201999
 (119) —
 2
 99
 (119) 2
 —
Total unrealized gains (losses) for the nine months ended September 30, 2019368
 (202) 2
 5
 368
 (202) 5
 2
 Exelon Generation PHI and Pepco
 Operating
Revenues		 Purchased
Power and
Fuel		 Operating and Maintenance Other, net 
Operating
Revenues
 
Purchased
Power and
Fuel
 Other, net Operating and Maintenance
Total realized (losses) gains for the three months ended June 30, 2018$(191) $78
 $1
 $—
 $(191) $78
 $—
 $1
Total realized gains (losses) for the six months ended June 30, 2018144
 (73) 2
 2
 144
 (73) 2
 2
Total unrealized (losses) gains for the three months ended June 30, 2018(71) 78
 —
 (4) (71) 78
 (4) —
Total unrealized gains (losses) for the six months ended June 30, 2018238
 25

—

(3) 238
 25
 (3) —
 Exelon Generation PHI and Pepco
 Operating
Revenues		 Purchased
Power and
Fuel		 Operating and Maintenance Other, net 
Operating
Revenues
 
Purchased
Power and
Fuel
 Other, net Operating and Maintenance
Total realized (losses) gains for the three months ended September 30, 2018$(176) $(83) $1
 $(1) $(176) $(83) $(1) $1
Total realized (losses) gains for the nine months ended September 30, 2018(32) (156) 3
 (1) (32) (156) (1) 3
Total unrealized (losses) for the three months ended September 30, 2018(64) (40) —
 (1) (64) (40) (1) —
Total unrealized gains (losses) for the nine months ended September 30, 2018174
 (15)
—

(5) 174
 (15) (5) —


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

Note 9 — Fair Value of Financial Assets and Liabilities

The table below discloses the significant inputs to the forward curve used to value these positions.
Type of trade Fair Value at June 30, 2019 Fair Value at December 31, 2018 
Valuation
Technique
 
Unobservable
Input
 2019 Range 2018 Range Fair Value at September 30, 2019 Fair Value at December 31, 2018 
Valuation
Technique
 
Unobservable
Input
 2019 Range 2018 Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)
 $542
 $443
 Discounted
Cash Flow		 Forward power
price		 $10-$118 $12-$174 $411
 $443
 Discounted
Cash Flow		 Forward power
price		 $11-$167 $12-$174
 

   
 Forward gas
price		 $1.54-$11.26 $0.78-$12.38 

   
 Forward gas
price		 $1.36-$10.82 $0.78-$12.38
 

   Option
Model		 Volatility
percentage		 8%-384% 10%-277% 

   Option
Model		 Volatility
percentage		 9%-200% 10%-277%
          
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
 $68
 $56
 Discounted
Cash Flow		 Forward power
price		 $10-$118 $14-$174 $67
 $56
 Discounted
Cash Flow		 Forward power
price		 $17-$167 $14-$174
          
Mark-to-market derivatives (Exelon and ComEd) $(273) $(249) Discounted
Cash Flow		 
Forward heat
rate(c)
 9x-10x 10x-11x $(280) $(249) Discounted
Cash Flow		 
Forward heat
rate(c)
 9x-10x 10x-11x
     Marketability
reserve		 4%-7% 4%-8%     Marketability
reserve		 4%-7% 4%-8%
     Renewable
factor		 88%-119% 86%-120%     Renewable
factor		 87%-119% 86%-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 $263$304 million and $76 million as of JuneSeptember 30, 2019 and December 31, 2018, respectively.
(c)Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.
10. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, interest rate risk and foreign exchange risk related to ongoing business operations.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at Generation and offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.

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

Note 10 — Derivative Financial Instruments

Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below that present fair value balances, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.
Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
Commodity Price Risk (All Registrants)
Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.
Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Derivative Financial Instruments

Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.

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

RegistrantCommodityAccounting TreatmentHedging instrument
ComEdElectricityNPNSFixed price contracts based on all requirements in the IPA procurement plans.
Electricity
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)
20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO(b)
GasNPNSFixed price contracts to cover about 20% of planned natural gas purchases in support of projected firm sales.
BGEElectricityNPNSFixed price contracts for all SOS requirements through full requirements contracts.
GasNPNSFixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
PepcoElectricityNPNSFixed price contracts for all SOS requirements through full requirements contracts.
DPLElectricityNPNSFixed price contracts for all SOS requirements through full requirements contracts.
GasNPNSFixed price contracts through full requirements contracts.
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability (c)
Exchange traded future contracts for 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACEElectricityNPNSFixed price contracts for all BGS requirements through full requirements contracts.
__________
(a)See Note 4 - Regulatory Matters for additional information.
(b)As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.
(c)The fair value of the DPL economic hedge is not material as of JuneSeptember 30, 2019 and December 31, 2018 and is not presented in the fair value tables below.

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

Note 10 — Derivative Financial Instruments


The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation ComEd and ExelonComEd as of JuneSeptember 30, 2019 and December 31, 2018:
June 30, 2019 Exelon Generation ComEd
Derivatives Total
Derivatives		 
Economic
Hedges
 
Proprietary
Trading
 
Collateral

 (a)(b)
 
Netting (a)
 Subtotal 
Economic
Hedges
Mark-to-market derivative assets
(current assets)
 $526
 $2,910
 $122
 $218
 $(2,724) $526
 $—
Mark-to-market derivative assets
(noncurrent assets)
 532
 1,618
 61
 122
 (1,269) 532
 —
Total mark-to-market derivative assets 1,058
 4,528
 183
 340
 (3,993) 1,058
 —
Mark-to-market derivative liabilities
(current liabilities)
 (157) (3,039) (78) 265
 2,724
 (128) (29)
Mark-to-market derivative liabilities
(noncurrent liabilities)
 (437) (1,576) (37) 151
 1,269
 (193) (244)
Total mark-to-market derivative liabilities (594) (4,615) (115) 416
 3,993
 (321) (273)
Total mark-to-market derivative net assets (liabilities) $464
 $(87) $68
 $756
 $—
 $737
 $(273)
December 31, 2018 Exelon Generation ComEd
Description Total
Derivatives		 Economic
Hedges		 Proprietary
Trading		 Collateral

(a)(b)		 Netting (a) Subtotal Economic
Hedges
September 30, 2019 Exelon Generation ComEd
Derivatives Total
Derivatives		 
Economic
Hedges
 
Proprietary
Trading
 
Collateral

 (a)(b)
 
Netting (a)
 Subtotal 
Economic
Hedges
Mark-to-market derivative assets
(current assets)		 $801
 $3,505
 $105
 $121
 $(2,930) $801
 $—
 $602
 $2,452
 $143
 $212
 $(2,205) $602
 $—
Mark-to-market derivative assets
(noncurrent assets)		 445
 1,266
 41
 51
 (913) 445
 —
 483
 1,386
 67
 104
 (1,074) 483
 —
Total mark-to-market derivative assets 1,246
 4,771
 146
 172
 (3,843) 1,246
 —
 1,085
 3,838
 210
 316
 (3,279) 1,085
 —
Mark-to-market derivative liabilities
(current liabilities)		 (473) (3,429) (74) 125
 2,931
 (447) (26) (224) (2,550) (101) 249
 2,205
 (197) (27)
Mark-to-market derivative liabilities
(noncurrent liabilities)		 (474) (1,203) (20) 60
 912
 (251) (223) (394) (1,324) (47) 156
 1,074
 (141) (253)
Total mark-to-market derivative liabilities (947) (4,632) (94) 185
 3,843
 (698) (249) (618) (3,874) (148) 405
 3,279
 (338) (280)
Total mark-to-market derivative net assets (liabilities) $299
 $139
 $52
 $357
 $—
 $548
 $(249) $467
 $(36) $62
 $721
 $—
 $747
 $(280)
December 31, 2018 Exelon Generation ComEd
Description Total
Derivatives		 Economic
Hedges		 Proprietary
Trading		 Collateral

(a)(b)		 Netting (a) Subtotal Economic
Hedges
Mark-to-market derivative assets
(current assets)		 $801
 $3,505
 $105
 $121
 $(2,930) $801
 $—
Mark-to-market derivative assets
(noncurrent assets)		 445
 1,266
 41
 51
 (913) 445
 —
Total mark-to-market derivative assets 1,246
 4,771
 146
 172
 (3,843) 1,246
 —
Mark-to-market derivative liabilities
(current liabilities)		 (473) (3,429) (74) 125
 2,931
 (447) (26)
Mark-to-market derivative liabilities
(noncurrent liabilities)		 (474) (1,203) (20) 60
 912
 (251) (223)
Total mark-to-market derivative liabilities (947) (4,632) (94) 185
 3,843
 (698) (249)
Total mark-to-market derivative net assets (liabilities) $299
 $139
 $52
 $357
 $—
 $548
 $(249)
_________
(a)Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are immaterial and not reflected in the table above.
(b)Of the collateral posted/(received), $358$306 million and $(94) million represents variation margin on the exchanges at JuneSeptember 30, 2019 and December 31, 2018 respectively.




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

Note 10 — Derivative Financial Instruments

Economic Hedges (Commodity Price Risk)
Generation. For the three and sixnine months ended JuneSeptember 30, 2019 and 2018, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.
 Three Months Ended
June 30,		 Six Months Ended
June 30,		 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018 2019 2018 2019 2018
Income Statement Location Gain (Loss) Gain (Loss) Gain (Loss) Gain (Loss)
Operating revenues $40
 $(7) $(10) $(107) $76
 $8
 $65
 $(99)
Purchased power and fuel (114) 96
 (84) (70) (45) 66
 (127) (4)
Total Exelon and Generation $(74) $89
 $(94) $(177) $31
 $74
 $(62) $(103)

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 JuneSeptember 30, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 92%-95%96%-99%, 70%-73%84%-87% and 40%-43%54%-57% for 2019, 2020 and 2021, respectively.
Proprietary Trading (Commodity Price Risk)
Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the three and sixnine months ended JuneSeptember 30, 2019 and 2018, net pre-tax commodity mark-to-market gains (losses) for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.
Interest Rate and Foreign Exchange Risk (Exelon and Generation)
Exelon and Generation utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $1,373$1,371 million and $1,420 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, for Exelon and $573$571 million and $620 million at JuneSeptember 30, 2019 and December 31, 2018, respectively, for Generation.
Generation utilizes foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, which are treated as economic hedges. The notional amounts were $219$257 million and $268 million at JuneSeptember 30, 2019 and December 31, 2018, respectively.
The mark-to-market derivative assets and liabilities as of JuneSeptember 30, 2019 and December 31, 2018 and the mark-to-market gains and losses for the three and sixnine months ended JuneSeptember 30, 2019 and 2018 were not material for Exelon and Generation.
Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date.
Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a

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

Note 10 — Derivative Financial Instruments

transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of JuneSeptember 30, 2019. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $70$68 million, $30 million, $32 million, $39 million, $15 million and $8 million as of JuneSeptember 30, 2019, respectively. 
Rating as of June 30, 2019Total 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, 2019Total 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$859
 $12
 $847
 2
 $249
$693
 $10
 $683
 —
 $—
Non-investment grade30
 11
 19
 


 


74
 38
 36
 


 


No external ratings                  
Internally rated — investment grade204
 1
 203
 


 


297
 1
 296
 


 


Internally rated — non-investment grade117
 11
 106
 


 


175
 24
 151
 


 


Total$1,210
 $35
 $1,175
 2
 $249
$1,239
 $73
 $1,166
 —
 $—
 
Net Credit Exposure by Type of Counterparty As of
June 30, 2019		 As of
September 30, 2019
Financial institutions $3
 $1
Investor-owned utilities, marketers, power producers 810
 875
Energy cooperatives and municipalities 302
 255
Other 60
 35
Total $1,175
 $1,166
_________ 
(a)As of JuneSeptember 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $25$18 million of cash and $9$55 million of letters of credit. The credit collateral does not include non-liquid collateral.
Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of JuneSeptember 30, 2019, the Utility Registrants’ counterparty credit risk with suppliers was immaterial.
Credit-Risk-Related Contingent Features (All Registrants)
Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Derivative Financial Instruments

to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and

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

margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:
Credit-Risk Related Contingent Features June 30, 2019 December 31, 2018 September 30, 2019 December 31, 2018
Gross fair value of derivative contracts containing this feature(a)
 $(1,119) $(1,723) $(1,249) $(1,723)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)
 824
 1,105
 947
 1,105
Net fair value of derivative contracts containing this feature(c)
 $(295) $(618) $(302) $(618)
_________
(a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.
(b)Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
(c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
As of JuneSeptember 30, 2019 and December 31, 2018, Exelon and Generation posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
 June 30, 2019 December 31, 2018 September 30, 2019 December 31, 2018
Cash collateral posted $781
 $418
 $787
 $418
Letters of credit posted 228
 367
 273
 367
Cash collateral held 64
 47
 96
 47
Letters of credit held 21
 44
 58
 44
Additional collateral required in the event of a credit downgrade below investment grade 1,513
 2,104
 1,481
 2,104

Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.
Utility Registrants
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Derivative Financial Instruments

PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with

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

thresholds contingent upon PECO’s, BGE, and DPL’s credit rating. As of JuneSeptember 30, 2019, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE or DPL lost their investment grade credit ratings as of JuneSeptember 30, 2019, they could have been required to post incremental collateral to its counterparties of $31$28 million, $31$26 million and $12$11 million, respectively.
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. 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.
Commercial Paper
The following table reflects the Registrants' commercial paper programs as of JuneSeptember 30, 2019 and December 31, 2018. Generation and PECO had no commercial paper borrowings as of both JuneSeptember 30, 2019 and December 31, 2018.
Outstanding Commercial
Paper as of		 Average Interest Rate on
Commercial Paper Borrowings as of		Outstanding Commercial
Paper as of		 Average Interest Rate on
Commercial Paper Borrowings as of
Commercial Paper IssuerJune 30, 2019 December 31, 2018 June 30, 2019 December 31, 2018September 30, 2019 December 31, 2018 September 30, 2019 December 31, 2018
Exelon$559
 $89
 2.60% 2.15%$519
 $89
 2.50% 2.15%
ComEd303
 —
 2.59% 2.14%387
 —
 2.51% 2.14%
BGE229
 35
 2.58% 2.18%—
 35
 2.49% 2.18%
PHI27
 54
 2.61% 2.15%132
 54
 2.52% 2.15%
PEPCO—
 40
 2.62% 2.24%12
 40
 2.61% 2.24%
DPL—
 —
 2.55% 2.07%57
 —
 2.42% 2.07%
ACE27
 14
 2.61% 2.21%63
 14
 2.57% 2.21%

See Note 13— Debt and Credit Agreements of the Exelon 2018 Form 10-K for additional information on the Registrants’ credit facilities.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million, which was renewed on March 22, 2018 with an expiration of March 21, 2019. The loan agreement was renewed on March 20, 2019 and will expire on March 19, 2020. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-Term borrowings.
Credit Agreements
On February 21, 2019, Generation entered into a credit agreement establishing a $100 million bilateral credit facility. The facility will mature in March 2021. This facility will solely be used by Generation to issue letters of credit.

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

Note 11 — Debt and Credit Agreements

Long-Term Debt
Issuance of Long-Term Debt
During the sixnine months ended JuneSeptember 30, 2019, the following long-term debt was issued:
Company Type Interest Rate Maturity Amount Use of Proceeds Type Interest Rate Maturity Amount Use of Proceeds
Generation Energy Efficiency Project Financing 3.95% August 31, 2020 $2
 Funding to install energy conservation measures for the Fort Meade project. Energy Efficiency Project Financing 3.95% August 31, 2020 $4
 Funding to install energy conservation measures for the Fort Meade project.
Generation Energy Efficiency Project Financing 3.46% May 1, 2020 $39
 Funding to install energy conservation measures for the Marine Corps. Logistics Project. Energy Efficiency Project Financing 3.46% May 1, 2020 $39
 Funding to install energy conservation measures for the Marine Corps. Logistics Project.
ComEd First Mortgage Bonds, Series 126 4.00% March 1, 2049 $400
 Repay a portion of ComEd’s outstanding commercial paper obligations and fund other general corporate purposes. First Mortgage Bonds, Series 126 4.00% March 1, 2049 $400
 Repay a portion of ComEd’s outstanding commercial paper obligations and fund other general corporate purposes.
PECO First and Refunding Mortgage Bonds 3.00% September 15, 2049 $325
 Repay short-term borrowings and for general corporate purposes
BGE Senior Notes 3.20% September 15, 2049 $400
 Repay commercial paper obligations and for general corporate purposes
Pepco First Mortgage Bonds 3.45% June 13, 2029 $150
 Repay existing indebtedness and for general corporate purposes First Mortgage Bonds 3.45% June 13, 2029 $150
 Repay existing indebtedness and for general corporate purposes
Pepco Unsecured Tax-Exempt Bonds 1.70% September 1, 2022 $110
 Repay existing indebtedness and for general corporate purposes Unsecured Tax-Exempt Bonds 1.70% September 1, 2022 $110
 Refinance existing indebtedness
ACE First Mortgage Bonds 3.50% May 21, 2029 $100
 Repay existing indebtedness and for general corporate purposes First Mortgage Bonds 3.50% May 21, 2029 $100
 Repay existing indebtedness and for general corporate purposes
ACE First Mortgage Bonds 4.14% May 21, 2049 $50
 Repay existing indebtedness and for general corporate purposes First Mortgage Bonds 4.14% May 21, 2049 $50
 Repay existing indebtedness and for general corporate purposes

Debt Covenants
As of JuneSeptember 30, 2019, the Registrants are in compliance with debt covenants, except for Antelope Valley's nonrecourse debt event of default as discussed below.
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing. 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.
Antelope Valley Solar Ranch One.  In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. As of JuneSeptember 30, 2019, approximately $500$495 million was outstanding. In 2017, Generation’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.
Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code, which created an event of default for Antelope Valley’s nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the ongoing event of default and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of JuneSeptember 30, 2019. Further, distributions from Antelope Valley to EGR IV are currently suspended.
ExGen Renewables IV.  In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Debt and Credit Agreements

financing. The loan is scheduled to mature on November 28, 2024. As of JuneSeptember 30, 2019, $796 million was outstanding.
Although Antelope Valley’s debt is in default, it is nonrecourse to EGR IV. However, if in the future Antelope Valley were to file for bankruptcy protection as a result of events culminating from PG&E’s bankruptcy proceedings this

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

would represent an event of default for EGR IV’s debt that would provide the lender with an opportunity to accelerate EGR IV’s debt.
See Note 13— Debt and Credit Agreements  of the Exelon 2018 Form 10-K for additional information on nonrecourse debt.
12. Income Taxes (All Registrants)
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 June 30, 2019Three Months Ended September 30, 2019
Exelon
Generation
ComEd
PECO
BGE PHI Pepco DPL ACEExelon
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%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 benefit5.4 5.5 8.2 (1.2) 6.5 4.8 2.0 7.0 7.06.4 5.2 8.1 (0.3) 6.3 4.8 1.9 6.6 6.9
Qualified NDT fund income5.1 16.2 — — — — — — —3.2 7.1 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.7) (1.9) (0.2) — (0.1) (0.2) (0.1) (0.2) (0.3)(4.1) (8.9) (0.2) — (0.1) (0.2) (0.1) (0.2) (0.3)
Plant basis differences(1.7) — (0.6) (5.9) (1.5) (1.7) (2.1) (0.3) (2.2)(1.7) — (1.0) (7.5) (1.1) (1.8) (2.6) (0.6) (1.9)
Production tax credits and other credits(0.9) (2.8) — — (0.1) — — — —(1.2) (2.7) — — — — — — —
Noncontrolling interests0.1 0.4 — — — — — — —(2.2) (4.8) — — — — — — —
Excess deferred tax amortization(7.8) — (9.0) (2.7) (7.9) (19.4) (18.3) (15.7) (23.1)(6.5) — (9.9) (3.6) (8.0) (17.7) (16.3) (13.5) (23.3)
Other1.9 0.2 0.4 0.1 1.7 0.9 0.5 — (2.4)0.7 0.5 0.4 (0.5) (0.2) 0.8 1.0 (0.1) 0.7
Effective income tax rate22.4% 38.6% 19.8% 11.3% 19.6% 5.4% 3.0% 11.8% —%15.6% 17.4% 18.4% 9.1% 17.9% 6.9% 4.9% 13.2% 3.1%
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Income Taxes

Three Months Ended June 30, 2018Three 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 rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%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 benefit3.4 4.3 8.1 (3.4) 6.5 6.2 4.7 6.5 7.6(1.2) (9.0) 8.3 (3.6) 7.3 0.2 1.0 6.6 7.3
Qualified NDT fund income0.2 0.5 — — — — — — —2.4 5.8 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.9) (2.4) (0.2) (0.1) (0.2) (0.2) (0.1) (0.3) (0.3)(0.6) (1.1) (0.2) (0.1) — (0.2) (0.1) (0.3) (0.3)
Plant basis differences(3.0) — (0.1) (17.2) (0.7) (1.2) (2.0) — (0.2)(2.5) — (0.3) (15.2) (0.8) (2.0) (3.4) (0.7) (1.3)
Production tax credits and other credits(1.7) (4.9) (0.1) — — — — — —(1.2) (2.9) (0.1) — — — — — —
Noncontrolling interests(1.5) (4.5) — — — — — — —(1.1) (2.8) — — — — — — —
Excess deferred tax amortization(5.2) — (7.6) (0.3) (7.2) (11.3) (11.7) (11.2) (8.8)(6.8) — (7.8) (4.6) (7.9) (17.7) (21.2) (14.0) (15.4)
Tax Cuts and Jobs Act of 2017(1.3) (1.7) (0.7) — 0.1 0.8 — — —1.3 3.5 — — — 0.2 0.1 — —
Other(0.2) (1.3) 0.4 (1.1) 0.8 (0.1) (0.4) 0.1 0.73.2 5.6 0.3 0.9 2.6 0.6 0.3 0.6 0.3
Effective income tax rate10.8% 11.0% 20.8% (1.1)% 20.3% 15.2% 11.5% 16.1% 20.0%14.5% 20.1% 21.2% (1.6)% 22.2% 2.1% (2.3)% 13.2% 11.6%
  
Six Months Ended June 30, 2019Nine Months Ended September 30, 2019
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon 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%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 benefit4.4 3.6 8.2 0.2 6.4 4.7 2.0 6.7 6.95.1 4.2 8.2 — 6.4 4.8 2.0 6.7 6.9
Qualified NDT fund income6.5 14.7 — — — — — — —5.3 11.9 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.6) (1.1) (0.2) — (0.1) (0.2) (0.1) (0.2) (0.3)(1.9) (4.0) (0.2) — (0.1) (0.2) (0.1) (0.2) (0.3)
Plant basis differences(1.5) — (0.6) (6.4) (1.0) (1.7) (2.0) (0.6) (2.2)(1.6) — (0.7) (6.8) (1.1) (1.8) (2.3) (0.6) (2.0)
Production tax credits and other credits(0.8) (1.8) — — — — — — —(1.0) (2.1) — — — — — — —
Noncontrolling interests(0.3) (0.8) — — — — — — —(1.0) (2.3) — — — — — — —
Excess deferred tax amortization(5.8) — (8.8) (2.6) (7.9) (19.4) (18.1) (15.6) (23.4)(6.0) — (9.2) (2.9) (7.9) (18.6) (17.3) (15.0) (23.4)
Other0.7 (0.4) 0.2 (0.1) 0.2 0.3 0.5 0.4 2.00.8 (0.1) 0.2 (0.2) 0.1 0.5 0.7 0.2 —
Effective income tax rate23.6% 35.2% 19.8% 12.1% 18.6% 4.7% 3.3% 11.7% 4.0%20.7% 28.6% 19.3% 11.1% 18.4% 5.7% 4.0% 12.1% 2.2%

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

Note 12 — Income Taxes

Six Months Ended June 30, 2018Nine 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 rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%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 3.4 8.1 (3.6) 6.4 5.5 3.7 6.4 7.21.7 (2.6) 8.2 (3.6) 6.6 2.7 2.4 6.5 7.3
Qualified NDT fund income(0.1) (0.4) — — — — — — —0.9 2.6 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(1.1) (3.3) (0.2) (0.1) (0.1) (0.2) (0.1) (0.3) (0.3)(0.9) (2.2) (0.2) (0.1) (0.1) (0.2) (0.1) (0.3) (0.3)
Plant basis differences(2.8) — — (15.6) (0.7) (1.8) (2.5) (0.7) (1.3)(2.7) — (0.1) (15.4) (0.7) (1.9) (2.9) (0.7) (1.3)
Production tax credits and other credits(2.3) (7.2) (0.1) — — — — — —(1.8) (5.1) (0.1) — — — — — —
Noncontrolling interests(1.1) (3.5) — — — — — — —(1.1) (3.2) — — — — — — —
Excess deferred tax amortization(5.6) — (7.5) (2.7) (8.2) (11.0) (12.1) (9.4) (8.8)(6.1) — (7.6) (3.4) (8.1) (14.5) (16.5) (11.0) (14.0)
Tax Cuts and Jobs Act of 2017(0.6) (0.9) (0.3) — — 0.5 — — —0.2 1.3 (0.2) — — 0.3 — — —
Other(1.7) (1.3) 0.1 (0.4) 0.2 (0.1) (0.4) 0.4 (1.1)0.4 2.0 0.1 — 0.9 0.3 — 0.4 0.9
Effective income tax rate9.5% 7.8% 21.1% (1.4)% 18.6% 13.9% 9.6% 17.4% 16.7%11.6% 13.8% 21.1% (1.5)% 19.6% 7.7% 3.9% 15.9% 13.6%

Accounting for Uncertainty in Income Taxes
The RegistrantsExelon, Generation, ComEd, PHI and ACE have the following unrecognized tax benefits as of JuneSeptember 30, 2019 and December 31, 2018:2018. PECO, BGE, Pepco and DPL do not have unrecognized tax benefits for the periods presented.
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PHI ACE
June 30, 2019$448
 $411
 $—
 $—
 $—
 $45
 $—
 $—
 $14
September 30, 2019$448
 $411
 $—
 $45
 $14
December 31, 2018$477
 $408
 $2
 $—
 $—
 $45
 $—
 $—
 $14
$477
 $408
 $2
 $45
 $14
In 2016, the Tax Court held that Exelon was not entitled to defer a gain on its 1999 like-kind exchange transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for penalties and interest on the penalties. Exelon had fully paid the amounts assessed resulting from the Tax Court decision in 2017. In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the Tax Court’s decision. Exelon filed a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December 2018.
In the first quarter of 2019, Exelon elected not to seek a further review by the U.S. Supreme Court. As a result, Exelon's and ComEd's unrecognized tax benefits decreased by approximately $33 million and $2 million, respectively, in the first quarter of 2019.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Income Taxes

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
Settlement of Income Tax Audits, Refund Claims, and Litigation
As of June 30, 2019, Exelon, Generation, PHI and ACE have approximately $425 million, $411 million, $14 million and $14 million, respectively, ofthe following unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, and the outcomes of pending court cases. Ofcases as of September 30, 2019:
Exelon(a)

Generation(a)

PHI(b)

ACE(b)
$425

$411

$14

$14
__________
(a)Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate.
(b)The unrecognized tax benefit related to PHI and ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Other Income Tax Matters
Marginal State Income Tax Rate (Exelon, Generation)
In the above unrecognizedthird quarter of 2019, Exelon reviewed and updated its marginal state income tax benefits, Exelon and Generation have $411 million that, if recognized, would decreaserates based on 2018 state apportionment rates. As a result of the effective tax rate. The unrecognized tax benefits related to PHI and ACE, ifrate changes, the following accounting adjustments were recorded as of September 30, 2019:

  Exelon Generation
Increase to deferred income tax liability $23
 $9
Increase to income tax expense, net of federal taxes 23
 9
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

recognized, may be included in future regulated base rates and that portion would have no impact to the effective tax rate.
State Income Tax Law Changes
On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation and ComEd do not expect a material impact to their financial statements as a result of the rate change.
13. Nuclear Decommissioning (Exelon and Generation)
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 financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC within Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 13 — Nuclear Decommissioning

The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2018 to JuneSeptember 30, 2019:
Nuclear decommissioning ARO at December 31, 2018 (a)(b)
$10,005
$10,005
Sale of Oyster Creek(755)
Accretion expense243
361
Net increase due to changes in, and timing of, estimated future cash flows232
211
Costs incurred related to decommissioning plants(43)(52)
Nuclear decommissioning ARO at June 30, 2019 (a)(b)
$10,437
Nuclear decommissioning ARO at September 30, 2019 (a)
$9,770
_________
(a)Includes $99$127 million and $22 million as the current portion of the ARO at JuneSeptember 30, 2019 and December 31, 2018, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.
(b)Includes $755 million and $772 million of ARO related to Oyster Creek which iswas classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at June 30, 2019 and December 31, 2018, respectively.2018. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.
During the sixnine months ended JuneSeptember 30, 2019, Exelon's and Generation’s total nuclear ARO increaseddecreased by approximately $432$235 million, primarily reflecting the sale of Oyster Creek, partially offset by the accretion of the ARO liability due to the passage of time and the net impacts of ARO updates completed during the first quarterand third quarters of 2019.
The first quarter 2019 ARO update includesincluded an increase of approximately $330 million for a change in the assumed retirement timing probabilities for certain economically challenged nuclear plants and a $110 million decrease for the impacts of revised decommissioning cost estimates for TMI which incorporate site specific decommissioning planning activities in anticipationassociated with the early retirement of itsTMI on September 2019 shutdown date. Approximately $85 million of the20, 2019. The TMI ARO adjustment resulted in aan $85 million decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. See Note 8 — Early Plant Retirements for additional information.
The third quarter 2019 ARO update included a decrease of approximately $300 million due to lower estimated costs to decommission Nine Mile Point, Ginna, Braidwood, Byron and LaSalle nuclear units resulting from the completion of updated cost studies, partially offset by an increase of approximately $280 million for other impacts that included updated cost escalation rates, primarily for labor, equipment and materials, and current discount rates. The third quarter ARO adjustment resulted in a $65 million decrease in Operating and maintenance expense within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income.
NDT Funds (Exelon and Generation)
Exelon and Generation had NDT funds totaling $13,498$12,862 million and $12,695 million at JuneSeptember 30, 2019 and December 31, 2018, respectively. The NDT funds include $857 million andincluded $890 million at June 30, 2019 and December 31, 2018, respectively, related to Oyster Creek NDT funds which arewere classified as Assets held for sale in Exelon's and Generation's Consolidated Balance Sheets. See Note 3 — Mergers, Acquisitions and Dispositions for additional information regarding the sale of Oyster Creek. The NDT funds also include $127$156 million and $144 million for the current portion of the NDT funds at JuneSeptember 30, 2019 and December 31, 2018, respectively, which are

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

included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 17 — Supplemental Financial Information for additional information on activities of the NDT funds.
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 April 1, 2019 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 13 — Nuclear Decommissioning

April 1, 2019 submittal. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for information regarding the amount collected from PECO ratepayers for decommissioning cost.
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 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 defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits.
Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP are being amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan.
Defined Benefit Pension and Other Postretirement BenefitsOPEB
During the first quarter of 2019, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2019. This valuation resulted in an increase to the pension and OPEB obligations of $75 million and $36 million, respectively. Additionally, accumulated other comprehensive loss increased by $39 million (after-tax) and regulatory assets and liabilities increased by $53 million and decreased by $5 million, respectively.
The majority of the 2019 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 4.31%. The majority of the 2019 other postretirement benefitOPEB cost is calculated using an expected long-term rate of return on plan assets of 6.67% for funded plans and a discount rate of 4.30%.

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 table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and sixnine months ended JuneSeptember 30, 2019 and 2018.
Pension Benefits
Three Months Ended June 30,		 Other Postretirement Benefits
Three Months Ended June 30,		Pension Benefits
Three Months Ended September 30,		 OPEB
Three Months Ended September 30,
2019 2018 2019 20182019 2018 2019 2018
Components of net periodic benefit cost:              
Service cost$89
 $102
 $24
 $28
$89
 $100
 $23
 $28
Interest cost221
 200
 47
 44
221
 201
 47
 43
Expected return on assets(306) (313) (38) (43)(306) (312) (38) (43)
Amortization of:              
Prior service benefit—
 —
 (44) (47)—
 —
 (45) (47)
Actuarial loss103
 157
 10
 16
104
 158
 11
 18
Settlement charges—
 1
 —
 —
7
 —
 —
 —
Contractual termination benefits1
 —
 —
 —
Net periodic benefit cost$107
 $147
 $(1) $(2)$116
 $147
 $(2) $(1)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
        

Pension Benefits
Six Months Ended June 30,		 Other Postretirement Benefits
Six Months Ended June 30,
 2019 2018 2019 2018
Components of net periodic benefit cost:

 

 

 

Service cost$178
 $202
 $47
 $56
Interest cost442
 401
 94
 88
Expected return on assets(612) (626) (77) (87)
Amortization of:       
Prior service cost (benefit)—
 1
 (89) (93)
Actuarial loss206
 314
 23
 33
Settlement charges—
 1
 —
 —
Net periodic benefit cost$214

$293

$(2)
$(3)
(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Retirement Benefits


Pension Benefits
Nine Months Ended September 30,		 OPEB
Nine Months Ended September 30,
 2019 2018 2019 2018
Components of net periodic benefit cost:

 

 

 

Service cost$267
 $303
 $70
 $84
Interest cost663
 602
 141
 131
Expected return on assets(918) (939) (115) (130)
Amortization of:       
Prior service cost (benefit)—
 1
 (134) (140)
Actuarial loss310
 472
 34
 50
Settlement charges7
 1
 —
 —
Contractual termination benefits1
 —
 —
 —
Net periodic benefit cost$330

$440

$(4)
$(5)

The amounts below represent Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, DPL's, and ACE'sthe Registrants' allocated pension and postretirement benefitOPEB plan costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment, net for the three and six months ended June 30, 2019 and 2018, while the non-service cost components are included in Other, net and Regulatory assets forassets. For Generation and the three and six months ended June 30, 2019 and 2018. For theUtility 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 in their consolidated financial statements for the three and six months ended June 30, 2019 and 2018.statements.

  Three Months Ended September 30, Nine Months Ended September 30,
Pension and OPEB Costs 2019 2018 2019 2018
Exelon $114
 $145
 $326
 $435
Generation 37
 50
 100
 151
ComEd 23
 45
 70
 133
PECO 4
 5
 9
 14
BGE 16
 15
 47
 44
PHI 23
 17
 71
 51
Pepco 6
 3
 19
 10
DPL 4
 2
 11
 5
ACE 4
 3
 12
 10

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

Note 14 — Retirement Benefits
  Three Months Ended June 30, Six Months Ended June 30,
Pension and Other Postretirement Benefit Costs 2019 2018 2019 2018
Exelon $106
 $145
 $212
 $290
Generation 31
 51
 62
 100
ComEd 23
 44
 47
 88
PECO 3
 5
 5
 10
BGE 16
 15
 30
 30
PHI 24
 17
 48
 34
Pepco 6
 3
 12
 8
DPL 4
 2
 8
 3
ACE 4
 3
 8
 6

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 sixnine months ended JuneSeptember 30, 2019 and 2018, respectively.
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended September 30, Nine Months Ended September 30,
Savings Plan Matching Contributions 2019 2018 2019 2018 2019 2018 2019 2018
Exelon $33
 $50

$64

$82
 $36
 $44

$101

$126
Generation 14
 28
 28
 43
 14
 23
 41
 65
ComEd 9
 8
 16
 15
 9
 8
 26
 23
PECO 2
 2
 5
 4
 2
 2
 7
 7
BGE 2
 2
 4
 4
 4
 2
 9
 5
PHI 3
 3
 6
 6
 4
 4
 8
 10
Pepco 1
 1
 2
 2
 1
 1
 2
 2
DPL 1
 1
 1
 1
 1
 1
 2
 2
ACE —
 —
 1
 1
 1
 1
 1
 2


15. Changes in Accumulated Other Comprehensive Income (Exelon)
The following tables present changes in Exelon's AOCI, net of tax, by component:
Three Months Ended September 30, 2019Losses on Cash Flow Hedges 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates (b)
 Total
Beginning balance$(2) $(2,957) $(29) $(2) $(2,990)
OCI before reclassifications—
 6
 (2) —
 4
Amounts reclassified from AOCI—
 21
 —
 2
 23
Net current-period OCI—
 27
 (2) 2
 27
Ending balance$(2) $(2,930) $(31) $—
 $(2,963)
Three Months Ended September 30, 2018Losses on Cash Flow Hedges 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates (b)
 Total
Beginning balance$(2) $(2,890) $(29) $—
 $(2,921)
OCI before reclassifications—
 5
 2
 —
 7
Amounts reclassified from AOCI—
 45
 —
 —
 45
Net current-period OCI—
 50
 2
 —
 52
Ending balance$(2) $(2,840) $(27) $—
 $(2,869)
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

15.Note 15 — Changes in Accumulated Other Comprehensive Income (Exelon and Generation)
The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the six months ended June 30, 2019 and 2018:
Six Months Ended June 30, 2019Losses on Cash Flow Hedges 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates
 Total
Exelon(a)
         
Beginning balance$(2) $(2,960) $(33) $—
 $(2,995)
OCI before reclassifications—
 (39) 4
 (2) (37)
Amounts reclassified from AOCI(b)
—
 42
 —
 —
 42
Net current-period OCI—
 3
 4
 (2) 5
Ending balance$(2) $(2,957) $(29) $(2) $(2,990)
Generation(a)
        

Beginning balance$(4) $—
 $(33) $(1) $(38)
OCI before reclassifications—
 —
 4
 (2) 2
Amounts reclassified from AOCI—
 —
 —
 —
 —
Net current-period OCI—
 —
 4
 (2) 2
Ending balance$(4) $—
 $(29) $(3) $(36)

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

Six Months Ended June 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$(14) $10
 $(2,998)
(d) 
$(23) $(1) $(3,026)
OCI before reclassifications13
 —
 20
 (6) 1
 28
Amounts reclassified from AOCI(b)
(1) —
 88
 —
 —
 87
Net current-period OCI12
 —
 108
 (6) 1
 115
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)
—
 (10) —
 —
 —
 (10)
Ending balance$(2) $—
 $(2,890) $(29) $—
 $(2,921)
Generation(a)
          
Nine Months Ended September 30, 2019Losses on Cash Flow Hedges 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates (b)
 Total
Beginning balance$(16) $3
 $—
 $(23) $(1) $(37)$(2) $(2,960) $(33) $—
 $(2,995)
OCI before reclassifications13
 —
 —
 (6) 1
 8
—
 (32) 2
 (2) (32)
Amounts reclassified from AOCI(1) —
 —
 —
 —
 (1)—
 62
 —
 2
 64
Net current-period OCI12
 —
 —
 (6) 1
 7
—
 30
 2
 —
 32
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)
—
 (3) —
 —
 —
 (3)
Ending balance$(4) $—
 $—
 $(29) $—
 $(33)$(2) $(2,930) $(31) $—
 $(2,963)
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 (a)
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates (b)
 Total
Beginning balance$(14) $10
 $(2,998) $(23) $(1) $(3,026)
OCI before reclassifications11
 —
 22
 (4) 1
 30
Amounts reclassified from AOCI1
 —
 136
 —
 —
 137
Net current-period OCI12
 —
 158
 (4) 1
 167
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)
—
 (10) —
 —
 —
 (10)
Ending balance$(2) $—
 $(2,840) $(27) $—
 $(2,869)
_________
(a)AllAOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information. See Exelon's Statements of taxOperations and noncontrolling interests. Amounts in parenthesis represent a decrease inComprehensive Income for individual components of AOCI.
(b)See next tables for details about these reclassifications.All amounts are net of noncontrolling interests.
(c)Exelon 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 and $3 million for Exelon and Generation, respectively.Exelon. The amounts reclassified related to Rabbi Trusts. See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information.
(d)Exelon early adopted the new standard Reclassification of Certain Tax Effects from AOCI. The standard was adopted retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million, primarily related to deferred income taxes associated with Exelon’s pension and OPEB obligations. See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information.

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 six months ended June 30, 2019 and 2018. The following tables present amounts reclassified out of AOCI to Net income for Exelon during the three and six months ended June 30, 2019 and 2018.
Three Months Ended June 30, 2019
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
  Exelon  
Amortization of pension and other postretirement benefit plan items    
Prior service costs(b)
 $22
  
Actuarial losses(b)
 (49)  
  (27) Total before tax
  7
 Tax benefit
  $(20) Net of tax

Six Months Ended June 30, 2019
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
  Exelon  
Amortization of pension and other postretirement benefit plan items    
Prior service costs(b)
 $44
  
Actuarial losses(b)
 (100)  
  (56) Total before tax
  14
 Tax benefit
  $(42) Net of tax

Three Months Ended June 30, 2018
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
  Exelon  
Amortization of pension and other postretirement benefit plan items    
Prior service costs(b)
 $23
  
Actuarial losses(b)
 (83)  
  (60) Total before tax
  16
 Tax benefit
  $(44) Net of tax


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

Six Months Ended June 30, 2018
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
  Exelon  
Amortization of pension and other postretirement benefit plan items    
Prior service costs(b)
 $46
  
Actuarial losses(b)
 (166)  
  (120) Total before tax
  32
 Tax benefit
  $(88) Net of tax
_________
(a)Amounts in parenthesis represent a decrease in net income.
(b)This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information.
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss) during the three and six months ended June 30, 2019 and 2018::
 Three Months Ended June 30, Six Months Ended
June 30,
 2019 2018 2019 2018
Exelon       
Pension and non-pension postretirement benefit plans:       
Prior service benefit reclassified to periodic benefit cost$6
 $6
 $12
 $12
Actuarial loss reclassified to periodic benefit cost(13) (22) (26) (44)
Pension and non-pension postretirement benefit plans valuation adjustment—
 1
 14
 (6)
Change in unrealized loss on cash flow hedges—
 (1) —
 (4)
Change in unrealized gain (loss) on investments in unconsolidated affiliates1
 —
 1
 (1)
Total$(6) $(16) $1
 $(43)
        
Generation       
Change in unrealized gain (loss) on cash flow hedges$—
 $(1) $—
 $(4)
Change in unrealized gain (loss) on investments in unconsolidated affiliates1
 —
 1
 (1)
Total$1
 $(1) $1
 $(5)
 Three Months Ended September 30, Nine Months Ended September 30,
 2019 2018 2019 2018
Pension and non-pension postretirement benefit plans:       
Prior service benefit reclassified to periodic benefit cost$6
 $6
 $18
 $18
Actuarial loss reclassified to periodic benefit cost(13) (21) (39) (65)
Pension and non-pension postretirement benefit plans valuation adjustment—
 (2) 14
 (8)

16. Commitments and Contingencies (All Registrants)
The following is an update to the current status of commitments and contingencies set forth in Note 22 of the Exelon 2018 Form 10-K. See Note 5 — Mergers, Acquisitions and Dispositions of the Exelon 2018 Form 10-K for additional 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

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

Note 16 — Commitments and Contingencies

generationCommitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL and other required commitments. In addition,ACE). Approval of the orders approving the mergerPHI Merger in Delaware, New Jersey, Maryland and Maryland include a “most favored nation” provision which, generally, requires allocationthe District of merger benefits proportionally across all the jurisdictions.
Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL and ACE as of JuneSeptember 30, 2019:
DescriptionExpected Payment Period Exelon PHI Pepco DPL ACE
Rate credits2016 - 2021 $264
 $264
 $91
 $72
 $101
Energy efficiency2016 - 2021 117
 —
 —
 —
 —
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
 $320
 $120
 $89
 $111
Remaining commitments  $116
 $86
 $69
 $11
 $6
DescriptionExelon PHI Pepco DPL ACE
Total commitments$513
 $320
 $120
 $89
 $111
Remaining commitments(a)
112
 82
 67
 9
 6

_________
(a)Remaining commitments extend through 2026 and include rate credits, energy efficiency programs. and delivery system modernization.
In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia, and Delaware at an estimated cost of approximately $127 million, which will generate future earnings at Exelon and Generation. Investment costs, which are expected to be primarily capital in nature, are recognized as incurred and recorded in Exelon's and Generation's financial statements. As of JuneSeptember 30, 2019, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $102$107 million. Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the DPSC in March 2019. The third and final 40 MW wind REC tranche will be conducted in 2022.
Pursuant to the various jurisdictions' merger approval conditions, over specified periods Pepco, DPLCOMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 16 — Commitments 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.Contingencies

Commercial Commitments (All Registrants).The Registrants’ commercial commitments as of JuneSeptember 30, 2019, representing commitments potentially triggered by future events were as follows:follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE  Expiration within
Total 2019 2020 2021 2022 2023 2024 and beyond
Exelon             
Letters of credit $1,315
 $1,283
 $7
 $—
 $9
 $10
 $10
 $—
 $—
$1,718
 $1,192
 $515
 $11
 $—
 $—
 $—
Surety bonds(a)
 1,492
 1,271
 52
 9
 17
 39
 31
 4
 3
991
 315
 638
 38
 —
 —
 —
Financing trust guarantees 378
 —
 200
 178
 —
 —
 —
 —
 —
378
 —
 —
 —
 —
 —
 378
Guaranteed lease residual values(b)
 26
 —
 —
 —
 —
 26
 9
 11
 7
26
 —
 2
 3
 4
 3
 15
Total commercial commitments $3,211
 $2,554
 $259
 $187
 $26

$75
 $50
 $15
 $10
$3,113
 $1,507
 $1,155
 $52
 $4

$3
 $393
             
Generation             
Letters of credit$1,686
 $1,179
 $496
 $11
 $—
 $—
 $—
Surety bonds(a)
790
 298
 492
 —
 —
 —
 —
Total commercial commitments$2,476
 $1,477
 $988
 $11
 $—
 $—
 $—
             
ComEd             
Letters of credit$7
 $4
 $3
 $—
 $—
 $—
 $—
Surety bonds(a)
50
 5
 43
 2
 —
 —
 —
Financing trust guarantees200
 —
 —
 —
 —
 —
 200
Total commercial commitments$257
 $9
 $46
 $2
 $—
 $—
 $200
             
PECO             
Surety bonds(a)
$9
 $1
 $8
 $—
 $—
 $—
 $—
Financing trust guarantees178
 —
 —
 —
 —
 —
 178
Total commercial commitments$187
 $1
 $8
 $—
 $—
 $—
 $178
             
BGE             
Letters of credit$8
 $2
 $6
 $—
 $—
 $—
 $—
Surety bonds(a)
17
 2
 15
 —
 —
 —
 —
Total commercial commitments$25
 $4
 $21
 $—
 $—
 $—
 $—
             
PHI             
Letters of credit$11
 $1
 $10
 $—
 $—
 $—
 $—
Surety bonds(a)
24
 5
 19
 —
 —
 —
 —
Guaranteed lease residual values(b)
26
 —
 2
 3
 4
 3
 15
Total commercial commitments$61
 $6
 $31
 $3
 $4
 $3
 $15
             
Pepco             
Letters of credit$10
 $—
 $10
 $—
 $—
 $—
 $—
Surety bonds(a)
17
 2
 15
 —
 —
 —
 —
Guaranteed lease residual values(b)
9
 —
 —
 1
 1
 1
 6
Total commercial commitments$36
 $2
 $25
 $1
 $1
 $1
 $6
             
DPL             
Letters of credit$1
 $1
 $—
 $—
 $—
 $—
 $—
Surety bonds(a)
4
 2
 2
 —
 —
 —
 —
Guaranteed lease residual values(b)
11
 —
 1
 1
 2
 1
 6
Total commercial commitments$16
 $3
 $3
 $1
 $2
 $1
 $6
             
ACE             
Surety bonds(a)
$3
 $1
 $2
 $—
 $—
 $—
 $—
Guaranteed lease residual values(b)
7
 —
 1
 1
 1
 1
 3
Total commercial commitments$10
 $1
 $3
 $1
 $1
 $1
 $3
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 16 — Commitments and Contingencies

_________
(a)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(b)
Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $68 million $23 millionguaranteed by Exelon and PHI, of which is a guarantee by Pepco, $28$22 million by DPL, $29 million and $17 million is guaranteed by ACE.Pepco, DPL and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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

Nuclear Insurance (Exelon and Generation). Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.
The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of June 30, 2019, the current liability limit per incident is $13.9 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. Changes to account for the effects of inflation occur at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.5 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $2.9 billion, however any amounts payable under this secondary layer would be capped at $434 million per year.
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.9 billion limit for a single incident.
As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 2 — Variable Interest Entities of the Exelon 2018 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.
Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $334 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.
NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by Exelon will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.

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

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 cash flows.
Environmental Remediation Matters
General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact in the Registrants' financial statements.
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 4221 sites 21 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 21 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2023.2025.
PECO has identified 268 sites 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements and 9 that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.
BGE has identified 134 sites 9 of which have been remediated and approved by the MDE and 4 that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2019.2021.
DPL has identified 3 sites, for 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control. The remaining1 site that is currently under study and the required cost at the site is not expected to be material.
The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. 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.

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

Note 16 — Commitments and Contingencies

As of JuneSeptember 30, 2019 and December 31, 2018, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
June 30, 2019
Total environmental
investigation and
remediation reserve
 
Portion of total related to
MGP investigation and
remediation
Exelon$482

$345
Generation107
 —
ComEd318
 318
PECO25
 24
BGE5
 3
PHI27

—
Pepco24
 —
DPL1
 —
ACE1
 —
December 31, 2018
Total environmental
investigation and
remediation reserve
 
Portion of total related to
MGP investigation and
remediation
Exelon$496

$356
Generation108
 —
ComEd329
 327
PECO27
 25
BGE5
 4
PHI27

—
Pepco25
 —
DPL1
 —
ACE1
 —

 September 30, 2019 December 31, 2018
 
Total environmental
investigation and
remediation liabilities
 
Portion of total related to
MGP investigation and
remediation
 
Total environmental
investigation and
remediation liabilities
 
Portion of total related to
MGP investigation and
remediation
Exelon$507

$346
 $496

$356
Generation107
 —
 108
 —
ComEd328
 327
 329
 327
PECO20
 18
 27
 25
BGE3
 1
 5
 4
PHI49

—
 27

—
Pepco47
 —
 25
 —
DPL1
 —
 1
 —
ACE1
 —
 1
 —
Cotter Corporation (Exelon and Generation). The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.
In September 2018 the EPA issued its Record of Decision (ROD) Amendment for the selection of the final remedy. The ROD modified the EPA’s previously proposed plan for partial excavation of the radiological materials by reducing the depths of the excavation. The ROD also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in the 2020 - 2021 time frame. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. The EPA has established a deadline of October 2019 for the PRPs to provide a good faith offer to conduct, or finance, the Remedial Action work. This schedule can be extended by the EPA pending completion of the Remedial Design. 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. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred

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

to implement the required remediation remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Generation’s associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.
One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial statements.
In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater RI/FS. The
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 16 — Commitments and Contingencies

purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $20 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future financial statements.
In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million from all PRPs. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until August 2019February 2020 so that settlement discussions could proceed. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above.
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, which was deactivated in June 2012 and plant structure demolition was completed in July 2015.2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to

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

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)Generation, pursuant to Exelon's 2016 acquisition of PHI) 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 ana 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 September 16, 2021.
Upon DOEE’s approval of the final RI and FS Reports, Pepco and GenerationDOEE will have satisfied their obligations under the Consent Decree. At that point, DOEE willthen prepare a Proposed Plan regarding further response actions. After considering public comment on the Proposed Plan, DOEE willand issue a Record of Decision identifying any further response actions determined to be necessary.necessary, after considering public comment on the Proposed Plan. PHI, Pepco and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and certain federal agenciesthe National Park Service have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-D.C.Maryland-District of Columbia 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"Consultative Working Group”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 site RI/FS. In addition, the District of Columbia Council directed DOEE to form an official advisory committee made up of members of federal, state and local environmental regulators, community and environmental groups and various academic and technical experts to provide guidance and support to DOEE as the project progressed. This group, called the Anacostia Leadership Council, has met regularly since it was formed. Pepco responded that it will participatehas participated 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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 16 — Commitments and Contingencies

Group. In April 2018, DOEE released a draft remedial investigationRI 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 theThe District of Columbia Council extended thehas set a deadline of December 31, 2019 for completion of the Record of Decision from June 30, 2018 until December 31, 2019.Decision. 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 cannotand recorded a liability in the third quarter 2019 for management’s best estimate of its share based on DOEE’s stated position following a series of meetings attended by representatives from the reasonably possible range of loss at this timeAnacostia Leadership Council and no liability has been accrued for those future costs.the Consultative Working Group. A draft Feasibility Study ofFS, which Pepco believes will include the process to identify potential short-term remedies and actions based on the technical findings in the RI report and their estimated costs to the extent possible, is being prepared by the agenciesDOEE and is expected later in 2019, at which timethe fourth quarter of 2019. DOEE and likely the National Park Service will continue to oversee ongoing remediation efforts and potential longer-term remedies for the Anacostia River. Pepco will likely be inhas concluded that incremental exposure remains reasonably possible, however management cannot reasonably estimate a better position to estimate the range of loss.loss beyond the amounts recorded, which are included in the table above.
In addition to the activities associated with the remedial process outlined above, there is a complementary statutory program that requires an assessment to determine if any natural resources have been damaged as a result of the contamination that is being remediated, and, if so, that a plan be developed by the federal, state and local Natural Resource Damage Trustees, who are defined by CERCLA as the responsible parties for the restoration or compensation for any loss of those resources to restore them to their condition before injury from the environmental contaminants.contaminants at the site. If natural resources are notcannot be restored, then compensation for the injury can be sought from the party responsible for the release of the contaminants.parties. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also effectively restore habitat. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process it cannot reasonably estimate the range of loss.

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

Litigation and Regulatory Matters
Asbestos Personal Injury Claims (Exelon and Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.
At JuneSeptember 30, 2019 and December 31, 2018, Exelon and Generation had recorded estimated liabilities of approximately $84$83 million and $79 million, respectively, in total for asbestos-related bodily injury claims. As of JuneSeptember 30, 2019, approximately $24$25 million of this amount related to 244257 open claims presented to Generation, while the remaining $60$58 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.
ThereIt is a reasonable possibilityreasonably possible 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'sExelon’s and Generation'sGeneration’s financial statements.
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,
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 16 — Commitments and Contingencies

it is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2019,2020, could be material to Generation’s resultsfinancial statements.
Subpoenas (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of operations2019 from the U.S. Attorney’s Office for the Northern District of Illinois requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and cash flows.ComEd received a second grand jury subpoena from the U.S. Attorney's Office for the Northern District of Illinois requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it has also opened an investigation into their lobbying activities. Exelon and ComEd have cooperated fully and intend to continue to cooperate fully and expeditiously with the U.S. Attorney’s Office and the SEC. Exelon and ComEd cannot predict the outcome of the subpoenas or the SEC investigation.
General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

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

17. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
Taxes other than incomeTaxes other than income
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended June 30, 2019                 
Three Months Ended September 30, 2019Three Months Ended September 30, 2019                
Utility taxes(a)
$209
 $32
 $55
 $30
 $21
 $71
 $67
 $4
 $—
$241
 $29
 $66
 $38
 $21
 $86
 $81
 $5
 $—
Property148
 68
 9
 4
 37
 30
 21
 8
 1
148
 66
 7
 5
 39
 31
 21
 9
 —
Payroll61
 30
 7
 4
 4
 7
 2
 1
 1
57
 28
 7
 3
 4
 6
 2
 1
 1
                                  
Three Months Ended June 30, 2018                 
Three Months Ended September 30, 2018Three Months Ended September 30, 2018                
Utility taxes(a)
$218
 $29
 $60
 $30
 $21
 $78
 $73
 $5
 $—
$253
 $32
 $67
 $39
 $23
 $92
 $87
 $5
 $—
Property135
 65
 8
 4
 34
 24
 15
 8
 1
145
 70
 7
 4
 37
 26
 16
 9
 —
Payroll65
 34
 7
 4
 4
 6
 2
 1
 1
58
 31
 6
 3
 4
 5
 1
 1
 1
                                  
Six Months Ended June 30, 2019                 
Nine Months Ended September 30, 2019Nine Months Ended September 30, 2019                
Utility taxes(a)
$432
 $58
 $118
 $63
 $48
 $145
 $136
 $9
 $—
$672
 $87
 $183
 $102
 $68
 $231
 $217
 $14
 $—
Property296
 138
 15
 8
 75
 60
 43
 16
 1
444
 205
 22
 12
 114
 91
 64
 25
 2
Payroll127
 64
 14
 7
 8
 14
 3
 2
 2
185
 92
 21
 11
 13
 20
 5
 3
 2
                                  
Six Months Ended June 30, 2018                 
Nine Months Ended September 30, 2018Nine Months Ended September 30, 2018                
Utility taxes(a)
$452
 $60
 $121
 $63
 $47
 $161
 $151
 $10
 $—
$705
 $92
 $188
 $102
 $70
 $253
 $238
 $15
 $—
Property271
 134
 15
 7
 69
 46
 29
 16
 1
416
 204
 22
 12
 106
 71
 45
 24
 2
Payroll133
 68
 14
 8
 8
 14
 3
 2
 2
191
 99
 20
 11
 12
 19
 5
 3
 2
_________
(a)Generation’s utility tax represents gross receipts tax related to its retail operations, and the Utility Registrants' utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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


Note 17 — Supplemental Financial Information

 Other, Net
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended September 30, 2019                
Decommissioning-related activities:                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units$67
 $67
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units33
 33
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on NDT funds                 
Regulatory agreement units89
 89
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units55
 55
 —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(b)
(125) (125) —
 —
 —
 —
 —
 —
 —
Decommissioning-related activities119
 119
 —
 —
 —

—
 —
 —
 —
AFUDC — Equity22
 —
 4
 3
 6
 9
 7
 1
 1
Non-service net periodic benefit cost(2) —
 —
 —
 —
 —
 —
 —
 —
                  
Three Months Ended September 30, 2018                
Decommissioning-related activities:                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units$214
 $214
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units58
 58
 —
 —
 —
 —
 —
 —
 —
Net unrealized (losses) gains on NDT funds                 
Regulatory agreement units(66) (66) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units72
 72
 —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(b)
(110) (110) —
 —
 —
 —
 —
 —
 —
Decommissioning-related activities168
 168
 —
 —
 —

—

—
 —
 —
AFUDC — Equity16
 —
 4
 1
 5
 6
 6
 —
 —
Non-service net periodic benefit cost(12) —
 —
 —
 —
 —
 —
 —
 —
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

 Other, Net
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended June 30, 2019                 
Decommissioning-related activities:                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units$77
 $77
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units230
 230
 —
 —
 —
 —
 —
 —
 —
Net unrealized (losses) gains on NDT funds                 
Regulatory agreement units98
 98
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units(98) (98) —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(b)
(141) (141) —
 —
 —
 —
 —
 —
 —
Decommissioning-related activities166
 166
 —
 —
 —

—
 —
 —
 —
AFUDC — Equity21
 —
 4
 3
 5
 9
 6
 1
 2
Non-service net periodic benefit cost5
 —
 —
 —
 —
 —
 —
 —
 —
                  
Three Months Ended June 30, 2018                 
Decommissioning-related activities:                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units$216
 $216
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units143
 143
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on NDT funds                 
Regulatory agreement units(194) (194) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units(120) (120) —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(b)
(23) (23) —
 —
 —
 —
 —
 —
 —
Decommissioning-related activities22
 22
 —
 —
 —

—

—
 —
 —
AFUDC — Equity13
 —
 2
 —
 4
 7
 6
 1
 —
Non-service net periodic benefit cost(11) —
 —
 —
 —
 —
 —
 —
 —

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 17 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted) Supplemental Financial Information

Other, NetOther, Net
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Six Months Ended June 30, 2019                 
Nine Months Ended September 30, 2019Nine Months Ended September 30, 2019                
Decommissioning-related activities:                                  
Net realized income on NDT funds(a)
                                  
Regulatory agreement units$131
 $131
 $—
 $—
 $—
 $—
 $—
 $—
 $—
$197
 $197
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units283
 283
 —
 —
 —
 —
 —
 —
 —
316
 316
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on NDT funds                                  
Regulatory agreement units476
 476
 —
 —
 —
 —
 —
 —
 —
565
 565
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units182
 182
 —
 —
 —
 —
 —
 —
 —
236
 236
 —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(b)
(487) (487) —
 —
 —
 —
 —
 —
 —
(611) (611) —
 —
 —
 —
 —
 —
 —
Decommissioning-related activities585
 585
 —
 —
 —
 —
 —
 —
 —
703
 703
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity43
 —
 9
 6
 10
 18
 12
 2
 4
64
 —
 13
 9
 16
 26
 18
 3
 4
Non-service net periodic benefit cost10
 —
 —
 —
 —
 —
 —
 —
 —
8
 —
 —
 —
 —
 —
 —
 —
 —
                                  
Six Months Ended June 30, 2018                 
Nine Months Ended September 30, 2018Nine Months Ended September 30, 2018                
Decommissioning-related activities:                                  
Net realized income on NDT funds(a)
                                  
Regulatory agreement units$262
 $262
 $—
 $—
 $—
 $—
 $—
 $—
 $—
$476
 $476
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units199
 199
 —
 —
 —
 —
 —
 —
 —
257
 257
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on NDT funds                                  
Regulatory agreement units(268) (268) —
 —
 —
 —
 —
 —
 —
(335) (335) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units(215) (215) —
 —
 —
 —
 —
 —
 —
(143) (143) —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(b)
(1) (1) —
 —
 —
 —
 —
 —
 —
(110) (110) —
 —
 —
 —
 —
 —
 —
Decommissioning-related activities(23) (23) —
 —
 —
 —

—
 —
 —
145
 145
 —
 —
 —
 —

—
 —
 —
AFUDC — Equity31
 —
 8
 2
 8
 13
 12
 1
 —
47
 —
 12
 3
 13
 19
 17
 2
 —
Non-service net periodic benefit cost(21) —
 —
 —
 —
 —
 —
 —
 —
(33) —
 —
 —
 —
 —
 —
 —
 —
_________
(a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
(b)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.


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

Note 17 — Supplemental Financial Information

Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
Depreciation, amortization and accretionDepreciation, amortization and accretion
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Six Months Ended June 30, 2019                 
Nine Months Ended September 30, 2019Nine Months Ended September 30, 2019                
Property, plant and equipment(a)
$1,859
 $789
 $439
 $149
 $173
 $266
 $117
 $71
 $57
$2,803
 $1,184
 $661
 $225
 $263
 $405
 $178
 $109
 $89
Amortization of regulatory assets(a)
266
 —
 69
 15
 79
 103
 69
 20
 14
390
 —
 106
 22
 105
 157
 103
 29
 25
Amortization of intangible assets, net(a)
29
 25
 —
 —
 —
 —
 —
 —
 —
44
 37
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
5
 5
 —
 —
 —
 —
 —
 —
 —
14
 14
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
513
 513
 —
 —
 —
 —
 —
 —
 —
771
 771
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
250
 248
 —
 —
 —
 —
 —
 —
 —
371
 371
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$2,922

$1,580

$508

$164

$252
 $369
 $186

$91

$71
$4,393

$2,377

$767

$247

$368
 $562
 $281

$138

$114
                                  
Six Months Ended June 30, 2018                 
Nine Months Ended September 30, 2018Nine Months Ended September 30, 2018                
Property, plant and equipment(a)
$1,873
 $890
 $406
 $135
 $164
 $236
 $107
 $64
 $47
$2,829
 $1,347
 $613
 $204
 $249
 $355
 $161
 $97
 $70
Amortization of regulatory assets(a)
278
 —
 53
 14
 84
 127
 81
 24
 22
412
 —
 83
 20
 109
 200
 125
 38
 37
Amortization of intangible assets, net(a)
28
 24
 —
 —
 —
 —
 —
 —
 —
43
 36
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
10
 10
 —
 —
 —
 —
 —
 —
 —
8
 8
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
569
 569
 —
 —
 —
 —
 —
 —
 —
852
 852
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
242
 242
 —
 —
 —
 —
 —
 —
 —
367
 365
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$3,000

$1,735

$459

$149

$248
 $363
 $188

$88

$69
$4,511

$2,608

$696

$224

$358
 $555
 $286

$135

$107
_________
(a)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(b)Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(d)Included in Operating and maintenance expense in 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)

Note 17 — Supplemental Financial Information

Other non-cash operating activitiesOther non-cash operating activities
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Six Months Ended June 30, 2019                 
Nine Months Ended September 30, 2019Nine Months Ended September 30, 2019                
Pension and non-pension postretirement benefit costs$212
 $62
 $47
 $5
 $29
 $48
 $12
 $8
 $8
$324
 $98
 $70
 $9
 $45
 $71
 $19
 $11
 $12
Provision for uncollectible accounts45
 12
 16
 10
 4
 3
 2
 1
 —
89
 20
 26
 22
 5
 16
 7
 2
 6
Other decommissioning-related activity(a)
(260) (261) —
 —
 —
 —
 —
 —
 —
(400) (400) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
43
 43
 —
 —
 —
 —
 —
 —
 —
21
 21
 —
 —
 —
 —
 —
 —
 —
Amortization of rate stabilization deferral(10) —
 —
 —
 —
 (10) (8) (2) —
(8) —
 —
 —
 —
 (8) (9) 1
 —
Discrete impacts from EIMA and FEJA(c)
24
 —
 24
 —
 —
 —
 —
 —
 —
80
 —
 80
 —
 —
 —
 —
 —
 —
Long-term incentive plan35
 —
 —
 —
 —
 —
 —
 —
 —
33
 —
 —
 —
 —
 —
 —
 —
 —
Amortization of operating ROU asset115
 78
 1
 —
 15
 17
 4
 5
 2
193
 138
 2
 —
 23
 26
 6
 7
 4
Change in environmental liabilities23
 —
 —
 —
 —
 23
 23
 —
 —
                                  
Six Months Ended June 30, 2018                 
Nine Months Ended September 30, 2018Nine Months Ended September 30, 2018                
Pension and non-pension postretirement benefit costs$290
 $100
 $88
 $10
 $29
 $34
 $8
 $3
 $6
$435
 $151
 $133
 $14
 $43
 $51
 $10
 $5
 $10
Provision for uncollectible accounts77
 28
 18
 11
 5
 15
 7
 2
 5
133
 38
 30
 25
 6
 32
 12
 6
 14
Other decommissioning-related activity(a)
(61) (61) —
 —
 —
 —
 —
 —
 —
(39) (39) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
(7) (7) —
 —
 —
 —
 —
 —
 —
4
 4
 —
 —
 —
 —
 —
 —
 —
Amortization of rate stabilization deferral13
 —
 —
 —
 —
 13
 10
 3
 —
—
 —
 —
 —
 —
 —
 —
 —
 —
Discrete impacts from EIMA and FEJA(c)
14
 —
 14
 —
 —
 —
 —
 —
 —
27
 —
 27
 —
 —
 —
 —
 —
 —
Long-term incentive plan51
 —
 —
 —
 —
 —
 —
 —
 —
84
 —
 —
 —
 —
 —
 —
 —
 —
Asset retirement costs20
 —
 —
 —
 —
 20
 22
 (1) (1)
_______
(a)Includes the elimination of decommissioning-related activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations of the Exelon 2018 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.


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

Note 17 — Supplemental Financial Information

The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
June 30, 2019                 
September 30, 2019                 
Cash and cash equivalents$735
 $575
 $65
 $20
 $8
 $54
 $18
 $3
 $4
$1,683
 $1,019
 $76
 $224
 $130
 $99
 $18
 $11
 $13
Restricted cash252
 122
 77
 6
 1
 37
 34
 1
 2
309
 126
 124
 6
 1
 38
 34
 —
 3
Restricted cash included in other long-term assets191
 —
 174
 —
 —
 17
 —
 —
 17
186
 —
 171
 —
 —
 15
 —
 —
 15
Total cash, cash equivalents and restricted cash$1,178
 $697
 $316
 $26
 $9
 $108
 $52
 $4
 $23
$2,178
 $1,145
 $371
 $230
 $131
 $152
 $52
 $11
 $31
                                  
December 31, 2018                                  
Cash and cash equivalents$1,349
 $750
 $135
 $130
 $7
 $124
 $16
 $23
 $7
$1,349
 $750
 $135
 $130
 $7
 $124
 $16
 $23
 $7
Restricted cash247
 153
 29
 5
 6
 43
 37
 1
 4
247
 153
 29
 5
 6
 43
 37
 1
 4
Restricted cash included in other long-term assets185
 —
 166
 —
 —
 19
 —
 —
 19
185
 —
 166
 —
 —
 19
 —
 —
 19
Total cash, cash equivalents and restricted cash$1,781
 $903
 $330
 $135
 $13
 $186
 $53
 $24
 $30
$1,781
 $903
 $330
 $135
 $13
 $186
 $53
 $24
 $30
                                  
June 30, 2018                 
September 30, 2018                 
Cash and cash equivalents$694
 $420
 $30
 $18
 $7
 $195
 $47
 $141
 $6
$1,918
 $1,187
 $124
 $102
 $113
 $153
 $12
 $110
 $11
Restricted cash206
 130
 5
 5
 1
 38
 33
 —
 5
240
 152
 12
 5
 3
 42
 35
 —
 7
Restricted cash included in other long-term assets128
 —
 108
 —
 —
 20
 —
 —
 20
163
 —
 144
 —
 —
 19
 —
 —
 19
Total cash, cash equivalents and restricted cash$1,028
 $550
 $143
 $23
 $8
 $253
 $80
 $141
 $31
$2,321
 $1,339
 $280
 $107
 $116
 $214
 $47
 $110
 $37
                                  
December 31, 2017                                  
Cash and cash equivalents$898
 $416
 $76
 $271
 $17
 $30
 $5
 $2
 $2
$898
 $416
 $76
 $271
 $17
 $30
 $5
 $2
 $2
Restricted cash207
 138
 5
 4
 1
 42
 35
 —
 6
207
 138
 5
 4
 1
 42
 35
 —
 6
Restricted cash included in other long-term assets85
 —
 63
 —
 —
 23
 —
 —
 23
85
 —
 63
 —
 —
 23
 —
 —
 23
Total cash, cash equivalents and restricted cash$1,190
 $554
 $144
 $275
 $18
 $95
 $40
 $2
 $31
$1,190
 $554
 $144
 $275
 $18
 $95
 $40
 $2
 $31
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K. 

Supplemental Balance Sheet Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
 Unbilled customer revenues
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
September 30, 2019$1,256
 $676
 $212
 $102
 $103
 $163
 $91
 $38
 $34
December 31, 20181,656
 965
 223
 114
 168
 186
 97
 59
 30

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

Note 17 — Supplemental Balance SheetFinancial Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
 Unbilled customer revenues
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
June 30, 2019$1,352
 $703
 $218
 $121
 $115
 $195
 $107
 $47
 $41
December 31, 20181,656
 965
 223
 114
 168
 186
 97
 59
 30

Accrued expensesAccrued expenses
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
June 30, 2019                 
September 30, 2019                 
Compensation-related accruals(a)
$767
 $292
 $117
 $52
 $41
 $72
 $23
 $15
 $10
$880
 $336
 $133
 $48
 $63
 $86
 $26
 $17
 $13
Taxes accrued446
 304
 65
 14
 21
 75
 54
 13
 9
431
 247
 56
 13
 64
 80
 61
 17
 3
Interest accrued340
 76
 109
 33
 40
 50
 24
 8
 13
421
 106
 62
 33
 36
 78
 37
 20
 19
                                  
December 31, 2018                                  
Compensation-related accruals(a)
$1,191
 $479
 $187
 $49
 $68
 $99
 $29
 $19
 $12
$1,191
 $479
 $187
 $49
 $68
 $99
 $29
 $19
 $12
Taxes accrued412
 226
 71
 28
 46
 74
 58
 4
 5
412
 226
 71
 28
 46
 74
 58
 4
 5
Interest accrued334
 77
 105
 33
 39
 50
 25
 8
 12
334
 77
 105
 33
 39
 50
 25
 8
 12
_________
(a)Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
18. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources at each of the Registrants.
Exelon has eleven11 reportable segments, which include Generation's five5 reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, and PHI's three3 reportable segments consisting of Pepco, DPL and ACE. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income.
The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation’s five5 reportable segments are as follows:
•
Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.
•
Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.
•
New York represents operations within ISO-NY.
•
ERCOT represents operations within Electric Reliability Council of Texas.

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

Other Power Regions:
•
New England represents the operations within ISO-NE.
•
South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM.
•
West represents operations in the WECC, which includes California ISO.
•
Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.
The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 18 — Segment Information

presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.
During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region is no longer regularly reviewed as a separate region by the CODM nor is it presented separately in any external information presented to third parties. Information for the New England region is reviewed by the CODM as part of Other Power Regions. Exelon and Generation retrospectively applied this change.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and sixnine months ended JuneSeptember 30, 2019 and 2018 is as follows:
Three Months Ended JuneSeptember 30, 2019 and 2018
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Operating revenues(c):
                              
2019
Competitive businesses electric revenues$3,718
 $—
 $—
 $—
 $—
 $—
 $(250) $3,468
$4,314
 $—
 $—
 $—
 $—
 $—
 $(275) $4,039
Competitive businesses natural gas revenues333
 —
 —
 —
 —
 —
 —
 333
265
 —
 —
 —
 —
 —
 1
 266
Competitive businesses other revenues159
 —
 —
 —
 —
 —
 (1) 158
195
 —
 —
 —
 —
 —
 (1) 194
Rate-regulated electric revenues—
 1,351
 566
 540
 1,063
 —
 (8) 3,512
—
 1,583
 716
 619
 1,357
 —
 (7) 4,268
Rate-regulated natural gas revenues—
 —
 89
 109
 24
 —
 (4) 218
—
 —
 62
 84
 20
 —
 (3) 163
Shared service and other revenues—
 —
 —
 —
 4
 484
 (488) —
—
 —
 —
 —
 3
 474
 (478) (1)
Total operating revenues$4,210
 $1,351
 $655
 $649
 $1,091
 $484
 $(751) $7,689
$4,774
 $1,583
 $778
 $703
 $1,380
 $474
 $(763) $8,929


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

Note 18 — Segment Information

Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
2018
Competitive businesses electric revenues$3,939
 $—
 $—
 $—
 $—
 $—
 $(270) $3,669
$4,741
 $—
 $—
 $—
 $—
 $—
 $(306) $4,435
Competitive businesses natural gas revenues489
 —
 —
 —
 —
 —
 —
 489
397
 —
 —
 —
 —
 —
 —
 397
Competitive businesses other revenues151
 —
 —
 —
 —
 —
 (4) 147
140
 —
 —
 —
 —
 —
 (1) 139
Rate-regulated electric revenues—
 1,398
 560
 548
 1,045
 —
 (9) 3,542
—
 1,598
 700
 645
 1,334
 —
 (7) 4,270
Rate-regulated natural gas revenues—
 —
 93
 114
 28
 —
 (5) 230
—
 —
 57
 86
 24
 —
 (5) 162
Shared service and other revenues—
 —
 —
 —
 3
 487
 (491) (1)—
 —
 —
 —
 3
 458
 (461) —
Total operating revenues$4,579
 $1,398
 $653
 $662
 $1,076
 $487
 $(779) $8,076
$5,278
 $1,598
 $757
 $731
 $1,361
 $458
 $(780) $9,403
Intersegment revenues(d):
                              
2019$252
 $5
 $2
 $6
 $3
 $482
 $(750) $—
$275
 $4
 $1
 $6
 $4
 $474
 $(764) $—
2018273
 5
 2
 6
 3
 487
 (776) —
308
 4
 2
 6
 3
 456
 (779) —
Depreciation and amortization:                              
2019$409
 $257
 $83
 $117
 $188
 $25
 $—
 $1,079
$407
 $259
 $83
 $116
 $193
 $25
 $—
 $1,083
2018466
 231
 74
 114
 180
 23
 —
 1,088
468
 237
 75
 110
 192
 23
 —
 1,105
Operating expenses:                              
2019$4,096
 $1,040
 $510
 $569
 $926
 $484
 $(744) $6,881
$4,274
 $1,256
 $595
 $612
 $1,124
 $457
 $(759) $7,559
20184,298
 1,111
 526
 578
 923
 492
 (790) 7,138
4,961
 1,275
 603
 628
 1,116
 459
 (790) 8,252
Interest expense, net:                              
2019$116
 $89
 $33
 $29
 $67
 $75
 $—
 $409
$109
 $91
 $33
 $31
 $66
 $79
 $—
 $409
2018102
 85
 32
 25
 65
 64
 —
 373
101
 85
 32
 27
 65
 83
 —
 393
Income (loss) before income taxes:                              
2019$202
 $232
 $115
 $56
 $112
 $(73) $—
 $644
$501
 $245
 $154
 $67
 $203
 $(68) $—
 $1,102
2018209
 207
 95
 64
 99
 (61) —
 613
389
 245
 124
 81
 191
 (83) —
 947
Income Taxes:                              
2019$78
 $46
 $13
 $11
 $6
 $(10) $—
 $144
$87
 $45
 $14
 $12
 $14
 $—
 $—
 $172
201823
 43
 (1) 13
 15
 (27) —
 66
78
 52
 (2) 18
 4
 (13) —
 137
Net income (loss):              
              
2019$118
 $186
 $102
 $45
 $106
 $(63) $—
 $494
$244
 $200
 $140
 $55
 $189
 $(68) $—
 $760
2018181
 164
 96
 51
 84
 (34) —
 542
300
 193
 126
 63
 187
 (69) —
 800
Capital Expenditures                              
2019$383
 $459
 $225
 $284
 $340
 $11
 $—
 $1,702
$392
 $452
 $228
 $300
 $308
 $7
 $—
 $1,687
2018670
 495
 194
 210
 371
 (13) —
 1,927
362
 514
 204
 233
 359
 18
 —
 1,690


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

Note 18 — Segment Information

__________
(a)Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $35$43 million, sales to BGE of $57$65 million, sales to Pepco of $52$65 million, sales to DPL of $12$14 million and sales to ACE of $5$3 million in the Mid-Atlantic region, and sales to ComEd of $89$83 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $25$35 million, sales to BGE of $63$69 million, sales to Pepco of $46 million, sales to DPL of $30$26 million and sales to ACE of $6$10 million in the Mid-Atlantic region, and sales to ComEd of $103$122 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 in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(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.

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

Note 18 — Segment Information

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):
2019                      
Rate-regulated electric revenues$531
 $261
 $274
 $—
 $(3) $1,063
$642
 $299
 $419
 $—
 $(3) $1,357
Rate-regulated natural gas revenues—
 24
 —
 —
 —
 24
—
 20
 —
 —
 —
 20
Shared service and other revenues—
 2
 —
 97
 (95) 4
—
 —
 —
 92
 (89) 3
Total operating revenues$531
 $287
 $274
 $97
 $(98) $1,091
$642
 $319
 $419
 $92
 $(92) $1,380
2018                      
Rate-regulated electric revenues$523
 $261
 $265
 $—
 $(4) $1,045
$628
 $304
 $406
 $—
 $(4) $1,334
Rate-regulated natural gas revenues—
 28
 —
 —
 —
 28
—
 24
 —
 —
 —
 24
Shared service and other revenues—
 —
 —
 108
 (105) 3
—
 —
 —
 103
 (100) 3
Total operating revenues$523
 $289
 $265
 $108
 $(109) $1,076
$628
 $328
 $406
 $103
 $(104) $1,361
Intersegment revenues:                      
2019$1
 $2
 $1
 $98
 $(99) $3
$2
 $1
 $1
 $93
 $(93) $4
20182
 2
 1
 107
 (109) 3
2
 2
 1
 103
 (105) 3
Depreciation and amortization:                      
2019$93
 $45
 $40
 $10
 $—
 $188
$95
 $46
 $43
 $9
 $—
 $193
201892
 43
 36
 9
 —
 180
99
 47
 38
 8
 —
 192
Operating expenses:                      
2019$438
 $243
 $246
 $100
 $(101) $926
$515
 $268
 $340
 $95
 $(94) $1,124
2018438
 247
 240
 110
 (112) 923
516
 277
 322
 105
 (104) 1,116
Interest expense, net:                      
2019$34
 $15
 $15
 $3
 $—
 $67
$33
 $15
 $15
 $3
 $—
 $66
201832
 14
 16
 3
 —
 65
32
 15
 16
 2
 —
 65
Income (loss) before income taxes:                      
2019$66
 $34
 $14
 $106
 $(108) $112
$103
 $38
 $65
 $192
 $(195) $203
201861
 31
 10
 85
 (88) 99
87
 38
 69
 179
 (182) 191
Income Taxes:                      
2019$2
 $4
 $—
 $—
 $—
 $6
$5
 $5
 $2
 $3
 $(1) $14
20187
 5
 2
 1
 —
 15
(2) 5
 8
 (8) 1
 4
Net income (loss):                      
2019$64
 $30
 $14
 $(5) $3
 $106
$98
 $33
 $63
 $(9) $4
 $189
201854
 26
 8
 (7) 3
 84
89
 33
 61
 1
 3
 187
Capital Expenditures                      
2019$154
 $82
 $99
 $5
 $—
 $340
$157
 $85
 $73
 $(7) $—
 $308
2018160
 101
 107
 3
 —
 371
188
 88
 77
 6
 —
 359

__________
(a)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(b)Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided

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

Note 18 — Segment Information

by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
Three Months Ended June 30, 2019Three Months Ended September 30, 2019
Revenues from external parties(a)
 Intersegment
revenues
Total
Revenues
Revenues from external customers(a)
 Intersegment
revenues
Total
Revenues
Contracts with customers 
Other(b)
 Total Contracts with customers 
Other(b)
 Total 
Mid-Atlantic$1,162
 $21
 $1,183
 $6
 $1,189
$1,351
 $10
 $1,361
 $3
 $1,364
Midwest974
 68
 1,042
 (8) 1,034
1,052
 47
 1,099
 (17) 1,082
New York373
 17
 390
 —
 390
414
 15
 429
 —
 429
ERCOT178
 47
 225
 4
 229
288
 72
 360
 5
 365
Other Power Regions814
 64
 878
 (17) 861
873
 192
 1,065
 (25) 1,040
Total Competitive Businesses Electric Revenues3,501
 217
 3,718
 (15) 3,703
3,978
 336
 4,314
 (34) 4,280
Competitive Businesses Natural Gas Revenues177
 156
 333
 15
 348
160
 105
 265
 34
 299
Competitive Businesses Other Revenues(c)
108
 51
 159
 —
 159
112
 83
 195
 —
 195
Total Generation Consolidated Operating Revenues$3,786
 $424
 $4,210
 $—
 $4,210
$4,250
 $524
 $4,774
 $—
 $4,774

Three Months Ended June 30, 2018Three Months Ended September 30, 2018
Revenues from external customers(a) Intersegment
revenues		 Total
Revenues
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
Contracts with customers Other(b) Total Contracts with customers 
Other(b)
 Total 
Mid-Atlantic$1,220
 $58
 $1,278
 $4
 $1,282
$1,397
 $52
 $1,449
 $7
 $1,456
Midwest1,062
 73
 1,135
 (5) 1,130
1,095
 26
 1,121
 (4) 1,117
New York392
 (2) 390
 2
 392
475
 (6) 469
 —
 469
ERCOT165
 111
 276
 1
 277
156
 289
 445
 (1) 444
Other Power Regions761
 99
 860
 (39) 821
959
 298
 1,257
 (45) 1,212
Total Competitive Businesses Electric Revenues3,600
 339
 3,939
 (37) 3,902
4,082
 659
 4,741
 (43) 4,698
Competitive Businesses Natural Gas Revenues295
 194
 489
 37
 526
200
 197
 397
 43
 440
Competitive Businesses Other Revenues(c)
125
 26
 151
 —
 151
130
 10
 140
 —
 140
Total Generation Consolidated Operating Revenues$4,020
 $559
 $4,579
 $—
 $4,579
$4,412
 $866
 $5,278
 $—
 $5,278
__________
(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 unrealized mark-to-market gains of $38$77 million and losses of $5$6 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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

Note 18 — Segment Information

Revenues net of purchased power and fuel expense (Generation):
Three Months Ended June 30, 2019 Three Months Ended June 30, 2018Three Months Ended September 30, 2019 Three Months Ended September 30, 2018
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
Mid-Atlantic$644
 $8
 $652
 $722
 $13
 $735
$684
 $5
 $689
 $746
 $17
 $763
Midwest738
 (8) 730
 770
 2
 772
763
 (16) 747
 763
 5
 768
New York250
 3
 253
 259
 7
 266
288
 3
 291
 290
 2
 292
ERCOT80
 (1) 79
 129
 (47) 82
76
 (4) 72
 161
 (63) 98
Other Power Regions154
 (20) 134
 229
 (43) 186
212
 (28) 184
 226
 (46) 180
Total Revenues net of purchased power and fuel for Reportable Segments1,866

(18)
1,848

2,109

(68)
2,041
2,023

(40)
1,983

2,186

(85)
2,101
Other(b)
52
 18
 70
 190
 68
 258
100
 40
 140
 112
 85
 197
Total Generation Revenues net of purchased power and fuel expense$1,918

$—

$1,918

$2,299

$—

$2,299
$2,123

$—

$2,123

$2,298

$—

$2,298
__________
(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 unrealized mark-to-market lossesgains of $74$17 million and gains of $90$71 million in 2019 and 2018, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of $5$3 million decrease and $20$18 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

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

Note 18 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):
 Three Months Ended September 30, 2019
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$865
 $479
 $352
 $741
 $311
 $178
 $252
Small commercial & industrial393
 109
 64
 147
 41
 48
 58
Large commercial & industrial141
 63
 116
 297
 222
 26
 49
Public authorities & electric railroads12
 9
 7
 17
 11
 3
 3
Other(a)
222
 63
 82
 164
 58
 50
 56
Total rate-regulated electric revenues(b)
$1,633
 $723
 $621
 $1,366
 $643
 $305
 $418
Rate-regulated natural gas revenues             
Residential$—
 $38
 $49
 $9
 $—
 $9
 $—
Small commercial & industrial—
 17
 9
 4
 —
 4
 —
Large commercial & industrial—
 —
 20
 1
 —
 1
 —
Transportation—
 5
 —
 4
 —
 4
 —
Other(c)
—
 2
 5
 2
 —
 2
 —
Total rate-regulated natural gas revenues(d)
$—
 $62
 $83
 $20
 $—
 $20
 $—
Total rate-regulated revenues from contracts with customers$1,633
 $785
 $704
 $1,386
 $643
 $325
 $418
              
Other revenues             
Revenues from alternative revenue programs$(56) $(11) $(5) $(9) $(3) $(6) $1
Other rate-regulated electric revenues(e)
6
 4
 3
 3
 2
 —
 —
Other rate-regulated natural gas revenues(e)
—
 —
 1
 —
 —
 —
 —
Total other revenues$(50) $(7) $(1) $(6) $(1) $(6) $1
Total rate-regulated revenues for reportable segments$1,583
 $778
 $703
 $1,380
 $642
 $319
 $419
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Electric and Gas Revenue by Customer Class (Utility Registrants):
 Three Months Ended June 30, 2019
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$647
 $343
 $282
 $494
 $224
 $135
 $135
Small commercial & industrial349
 99
 59
 120
 35
 44
 41
Large commercial & industrial127
 52
 109
 278
 207
 25
 46
Public authorities & electric railroads10
 7
 6
 16
 8
 4
 4
Other(a)
227
 62
 82
 159
 56
 54
 50
Total rate-regulated electric revenues(b)
$1,360
 $563
 $538
 $1,067
 $530
 $262
 $276
Rate-regulated natural gas revenues             
Residential$—
 $49
 $60
 $11
 $—
 $11
 $—
Small commercial & industrial—
 33
 11
 7
 —
 7
 —
Large commercial & industrial—
 —
 23
 2
 —
 2
 —
Transportation—
 6
 —
 3
 —
 3
 —
Other(c)
—
 1
 7
 1
 —
 1
 —
Total rate-regulated natural gas revenues(d)
$—
 $89
 $101
 $24
 $—
 $24
 $—
Total rate-regulated revenues from contracts with customers$1,360
 $652
 $639
 $1,091
 $530
 $286
 $276
              
Other revenues             
Revenues from alternative revenue programs$(14) $(3) $6
 $(3) $(1) $—
 $(2)
Other rate-regulated electric revenues(e)
5
 6
 3
 3
 2
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 1
 —
 —
 —
 —
Total other revenues$(9) $3
 $10
 $—
 $1
 $1
 $(2)
Total rate-regulated revenues for reportable segments$1,351
 $655
 $649
 $1,091
 $531
 $287
 $274

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 18 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted) Segment Information

Three Months Ended June 30, 2018Three Months Ended September 30, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACEComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues                          
Residential$699
 $338
 $295
 $505
 $228
 $142
 $135
$861
 $458
 $366
 $726
 $306
 $180
 $240
Small commercial & industrial357
 97
 60
 115
 33
 44
 38
391
 108
 68
 140
 39
 48
 53
Large commercial & industrial127
 52
 101
 282
 212
 25
 45
131
 64
 117
 303
 230
 25
 48
Public authorities & electric railroads12
 6
 7
 16
 9
 3
 4
11
 7
 7
 14
 8
 3
 3
Other(a)
213
 60
 78
 133
 49
 41
 44
212
 59
 91
 156
 47
 47
 63
Total rate-regulated electric revenues(b)
$1,408
 $553
 $541
 $1,051
 $531
 $255
 $266
$1,606
 $696
 $649
 $1,339
 $630
 $303
 $407
Rate-regulated natural gas revenues                          
Residential$—
 $62
 $74
 $13
 $—
 $13
 $—
$—
 $36
 $46
 $8
 $—
 $8
 $—
Small commercial & industrial—
 25
 13
 8
 —
 8
 —
—
 15
 8
 5
 —
 5
 —
Large commercial & industrial—
 —
 23
 1
 —
 1
 —
—
 —
 17
 2
 —
 2
 —
Transportation—
 5
 —
 4
 —
 4
 —
—
 5
 —
 3
 —
 3
 —
Other(c)
—
 1
 12
 2
 —
 2
 —
—
 1
 12
 6
 —
 6
 —
Total rate-regulated natural gas revenues(d)
$—
 $93
 $122
 $28
 $—
 $28
 $—
$—
 $57
 $83
 $24
 $—
 $24
 $—
Total rate-regulated revenues from contracts with customers$1,408
 $646
 $663
 $1,079
 $531
 $283
 $266
$1,606
 $753
 $732
 $1,363
 $630
 $327
 $407
                          
Other revenues                          
Revenues from alternative revenue programs$(17) $2
 $(4) $(7) $(10) $4
 $(1)$(15) $1
 $(6) $(5) $(4) $—
 $(1)
Other rate-regulated electric revenues(e)
7
 5
 3
 4
 2
 2
 —
7
 3
 4
 3
 2
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 —
 —
 —
 —
 —
—
 —
 1
 —
 —
 —
 —
Total other revenues$(10) $7
 $(1) $(3) $(8) $6
 $(1)$(8) $4
 $(1) $(2) $(2) $1
 $(1)
Total rate-regulated revenues for reportable segments$1,398
 $653
 $662
 $1,076
 $523
 $289
 $265
$1,598
 $757
 $731
 $1,361
 $628
 $328
 $406
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $5$4 million, $1 million, $1$2 million, $3$4 million, $1$2 million, $2$1 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $5$4 million, $2 million, $2$1 million, $3 million $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of less than $1 million and $4 million at PECO and BGE, respectively, in 2019 and less than $1 million and $5 million at PECO and BGE, respectively, in 2018.
(e)Includes late payment charge revenues.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)


Note 18 — Segment Information

Nine Months Ended September 30, 2019 and 2018
 
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Operating revenues(c):
2019               
Competitive businesses electric revenues$12,365
 $—
 $—
 $—
 $—
 $—
 $(840) $11,525
Competitive businesses natural gas revenues1,479
 —
 —
 —
 —
 —
 —
 1,479
Competitive businesses other revenues436
 —
 —
 —
 —
 —
 (4) 432
Rate-regulated electric revenues—
 4,342
 1,901
 1,817
 3,574
 —
 (25) 11,609
Rate-regulated natural gas revenues—
 —
 432
 510
 116
 —
 (12) 1,046
Shared service and other revenues—
 —
 —
 —
 10
 1,410
 (1,415) 5
Total operating revenues$14,280
 $4,342
 $2,333
 $2,327
 $3,700
 $1,410
 $(2,296) $26,096
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
Shared service and other revenues               
Intersegment revenues(d):
               
2019$844
 $13
 $4
 $18
 $11
 $1,410
 $(2,300) $—
2018981
 23
 5
 18
 11
 1,392
 (2,430) —
Depreciation and amortization:               
2019$1,221
 $767
 $247
 $368
 $562
 $72
 $—
 $3,237
20181,383
 696
 224
 358
 555
 68
 —
 3,284
Operating expenses:               
2019$13,333
 $3,431
 $1,783
 $1,936
 $3,106
 $1,405
 $(2,291) $22,703
201814,475
 3,610
 1,853
 2,005
 3,165
 1,395
 (2,467) 24,036
Interest expense, net:               
2019$336
 $268
 $100
 $89
 $197
 $231
 $—
 $1,221
2018305
 261
 96
 78
 193
 205
 —
 1,138
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Six Months Ended June 30, 2019 and 2018
 
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Operating revenues(c):
2019               
Competitive businesses electric revenues$8,052
 $—
 $—
 $—
 $—
 $—
 $(565) $7,487
Competitive businesses natural gas revenues1,214
 —
 —
 —
 —
 —
 (1) 1,213
Competitive businesses other revenues240
 —
 —
 —
 —
 —
 (2) 238
Rate-regulated electric revenues—
 2,759
 1,185
 1,198
 2,218
 —
 (17) 7,343
Rate-regulated natural gas revenues—
 —
 369
 427
 95
 —
 (8) 883
Shared service and other revenues—
 —
 —
 —
 6
 940
 (944) 2
Total operating revenues$9,506
 $2,759
 $1,554
 $1,625
 $2,319
 $940
 $(1,537) $17,166
2018               
Competitive businesses electric revenues$8,448
 $—
 $—
 $—
 $—
 $—
 $(663) $7,785
Competitive businesses natural gas revenues1,444
 —
 —
 —
 —
 —
 (8) 1,436
Competitive businesses other revenues198
 —
 —
 —
 —
 —
 (2) 196
Rate-regulated electric revenues—
 2,910
 1,193
 1,206
 2,214
 —
 (27) 7,496
Rate-regulated natural gas revenues—
 —
 325
 433
 106
 —
 (9) 855
Shared service and other revenues—
 —
 —
 —
 7
 940
 (946) 1
Total operating revenues$10,090
 $2,910
 $1,518
 $1,639
 $2,327
 $940
 $(1,655) $17,769
Shared service and other revenues               
Intersegment revenues(d):
               
2019$568
 $9
 $3
 $12
 $7
 $935
 $(1,534) $—
2018672
 19
 3
 12
 7
 937
 (1,650) —
Depreciation and amortization:               
2019$814
 $508
 $164
 $252
 $369
 $47
 $—
 $2,154
2018914
 459
 149
 248
 363
 46
 —
 2,179
Operating expenses:               
2019$9,059
 $2,174
 $1,187
 $1,325
 $1,981
 $942
 $(1,526) $15,142
20189,515
 2,335
 1,249
 1,378
 2,048
 936
 (1,675) 15,786
Interest expense, net:               
2019$227
 $178
 $67
 $58
 $131
 $152
 $—
 $813
2018202
 175
 64
 51
 128
 125
 —
 745

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 18 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted) Segment Information

Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Income (loss) before income taxes:                              
2019$854
 $429
 $307
 $253
 $234
 $(151) $—
 $1,926
$1,355
 $674
 $461
 $320
 $436
 $(218) $—
 $3,028
2018412
 417
 207
 220
 173
 (114) —
 1,315
800
 663
 331
 301
 363
 (195) —
 2,263
Income Taxes:                              
2019$301
 $85
 $37
 $47
 $11
 $(27) $—
 $454
$388
 $130
 $51
 $59
 $25
 $(27) $—
 $626
201832
 88
 (3) 41
 24
 (57) —
 125
110
 140
 (5) 59
 28
 (70) —
 262
Net income (loss):                              
2019$540
 $344
 $270
 $206
 $223
 $(123) $—
 $1,460
$784
 $544
 $410
 $261
 $412
 $(191) $—
 $2,220
2018368
 329
 210
 179
 149
 (56) —
 1,179
667
 523
 336
 242
 336
 (125) —
 1,979
Capital Expenditures                              
2019$890
 $961
 $447
 $542
 $698
 $34
 $—
 $3,572
$1,282
 $1,413
 $675
 $842
 $1,006
 $41
 $—
 $5,259
20181,298
 1,026
 411
 434
 629
 9
 —
 3,807
1,660
 1,540
 615
 667
 988
 27
 —
 5,497
Total assets:                              
June 30, 2019$48,402
 $31,889
 $11,002
 $10,006
 $22,454
 $8,142
 $(10,299) $121,596
September 30, 2019$47,984
 $32,326
 $11,379
 $10,304
 $22,576
 $8,254
 $(10,085) $122,738
December 31, 201847,556
 31,213
 10,642
 9,716
 21,984
 8,355
 (9,800) 119,666
47,556
 31,213
 10,642
 9,716
 21,984
 8,355
 (9,800) 119,666
__________
(a)Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $80$123 million, sales to BGE of $133$199 million, sales to Pepco of $122$188 million, sales to DPL of $35$50 million and sales to ACE of $13$16 million in the Mid-Atlantic region, and sales to ComEd of $183$266 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $61$97 million, sales to BGE of $128$198 million, sales to Pepco of $98$143 million, sales to DPL of $76$103 million and sales to ACE of $12$21 million in the Mid-Atlantic region, and sales to ComEd of $297$419 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 in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(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.

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

Note 18 — Segment Information

PHI:
 Pepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHI
Operating revenues(a):
           
2019           
Rate-regulated electric revenues$1,748
 $871
 $966
 $(1) $(10) $3,574
Rate-regulated natural gas revenues—
 116
 —
 —
 —
 116
Shared service and other revenues—
 —
 —
 298
 (288) 10
Total operating revenues$1,748
 $987
 $966
 $297
 $(298) $3,700
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
Intersegment revenues:           
2019$5
 $5
 $2
 $297
 $(298) $11
20185
 6
 2
 325
 (327) 11
Depreciation and amortization:           
2019$281
 $138
 $114
 $29
 $—
 $562
2018286
 135
 107
 27
 —
 555
Operating expenses:           
2019$1,444
 $820
 $838
 $302
 $(298) $3,106
20181,454
 859
 847
 329
 (324) 3,165
Interest expense, net:           
2019$100
 $45
 $44
 $8
 $—
 $197
201896
 42
 48
 7
 —
 193
Income (loss) before income taxes:           
2019$226
 $132
 $89
 $411
 $(422) $436
2018181
 107
 88
 326
 (339) 363
Income Taxes:           
2019$9
 $16
 $2
 $(1) $(1) $25
20187
 17
 12
 (8) —
 28
Net income (loss):           
2019$217
 $116
 $87
 $(19) $11
 $412
2018174
 90
 76
 (15) 11
 336
Capital Expenditures           
2019$455
 $245
 $300
 $6
 $—
 $1,006
2018475
 254
 247
 12
 —
 988
Total assets:           
September 30, 2019$8,603
 $4,724
 $3,916
 $11,071
 $(5,738) $22,576
December 31, 20188,299
 4,588
 3,699
 10,819
 (5,421) 21,984

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

PHI:
 Pepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHI
Operating revenues(a):
           
2019           
Rate-regulated electric revenues$1,106
 $572
 $547
 $—
 $(7) $2,218
Rate-regulated natural gas revenues—
 95
 —
 —
 —
 95
Shared service and other revenues—
 —
 —
 205
 (199) 6
Total operating revenues$1,106
 $667
 $547
 $205
 $(206) $2,319
2018           
Rate-regulated electric revenues$1,080
 $567
 $575
 $—
 $(8) $2,214
Rate-regulated natural gas revenues—
 106
 —
 —
 —
 106
Shared service and other revenues—
 —
 —
 221
 (214) 7
Total operating revenues$1,080
 $673
 $575
 $221
 $(222) $2,327
Intersegment revenues:           
2019$3
 $3
 $1
 $205
 $(205) $7
20183
 4
 2
 220
 (222) 7
Depreciation and amortization:           
2019$186
 $91
 $71
 $20
 $1
 $369
2018188
 88
 69
 19
 (1) 363
Operating expenses:           
2019$929
 $550
 $498
 $208
 $(204) $1,981
2018939
 582
 526
 224
 (223) 2,048
Interest expense, net:           
2019$68
 $30
 $28
 $5
 $—
 $131
201863
 27
 32
 5
 1
 128
Income (loss) before income taxes:           
2019$123
 $94
 $25
 $219
 $(227) $234
201894
 69
 18
 149
 (157) 173
Income Taxes:           
2019$4
 $11
 $1
 $(4) $(1) $11
20189
 12
 3
 —
 —
 24
Net income (loss):           
2019$119
 $83
 $24
 $(10) $7
 $223
201885
 57
 15
 (15) 7
 149
Capital Expenditures           
2019$298
 $160
 $227
 $13
 $—
 $698
2018287
 166
 170
 6
 —
 629
Total assets:           
June 30, 2019$8,556
 $4,683
 $3,886
 $11,168
 $(5,839) $22,454
December 31, 20188,299
 4,588
 3,699
 10,819
 (5,421) 21,984


COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 18 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted) Segment Information

__________
(a)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(b)Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
Six Months Ended June 30, 2019Nine Months Ended September 30, 2019
Revenues from external parties(a)
 
Intersegment
Revenues
 
Total
Revenues
Revenues from external customers(a)
 
Intersegment
Revenues
 
Total
Revenues
Contracts with customers 
Other(b)
 Total Contracts with customers 
Other(b)
 Total 
Mid-Atlantic$2,448
 $(2) $2,446
 $(1) $2,445
$3,798
 $9
 $3,807
 $2
 $3,809
Midwest2,030
 126
 2,156
 (14) 2,142
3,083
 172
 3,255
 (31) 3,224
New York781
 1
 782
 —
 782
1,195
 16
 1,211
 —
 1,211
ERCOT307
 126
 433
 8
 441
594
 198
 792
 13
 805
Other Power Regions1,976
 259
 2,235
 (21) 2,214
2,849
 451
 3,300
 (46) 3,254
Total Competitive Businesses Electric Revenues7,542
 510
 8,052
 (28) 8,024
11,519
 846
 12,365
 (62) 12,303
Competitive Businesses Natural Gas Revenues763
 451
 1,214
 28
 1,242
1,041
 438
 1,479
 62
 1,541
Competitive Businesses Other Revenues(c)
230
 10
 240
 —
 240
343
 93
 436
 —
 436
Total Generation Consolidated Operating Revenues$8,535
 $971
 $9,506
 $—
 $9,506
$12,903
 $1,377
 $14,280
 $—
 $14,280

Six Months Ended June 30, 2018Nine Months Ended September 30, 2018
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
Contracts with customers 
Other(b)
 Total Contracts with customers 
Other(b)
 Total 
Mid-Atlantic$2,574
 $138
 $2,712
 $10
 $2,722
$3,971
 $191
 $4,162
 $17
 $4,179
Midwest2,336
 143
 2,479
 (4) 2,475
3,432
 169
 3,601
 (8) 3,593
New York831
 (31) 800
 1
 801
1,305
 (37) 1,268
 1
 1,269
ERCOT315
 169
 484
 2
 486
470
 459
 929
 1
 930
Other Power Regions1,696
 277
 1,973
 (71) 1,902
2,656
 574
 3,230
 (116) 3,114
Total Competitive Businesses Electric Revenues7,752
 696
 8,448
 (62) 8,386
11,834
 1,356
 13,190
 (105) 13,085
Competitive Businesses Natural Gas Revenues816
 628
 1,444
 62
 1,506
1,016
 823
 1,839
 105
 1,944
Competitive Businesses Other Revenues(c)
258
 (60) 198
 —
 198
385
 (46) 339
 —
 339
Total Generation Consolidated Operating Revenues$8,826
 $1,264
 $10,090
 $—
 $10,090
$13,235
 $2,133
 $15,368
 $—
 $15,368
__________
(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 unrealized mark-to-market gains of $64 million and losses of $14 million and $102$96 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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

Note 18 — Segment Information

Revenues net of purchased power and fuel expense (Generation):
Six Months Ended June 30, 2019 Six Months Ended June 30, 2018Nine Months Ended September 30, 2019 Nine Months Ended September 30, 2018
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
Mid-Atlantic$1,324
 $10
 $1,334
 $1,558
 $28
 $1,586
$2,007
 $16
 $2,023
 $2,303
 $45
 $2,348
Midwest1,506
 (6) 1,500
 1,617
 14
 1,631
2,269
 (22) 2,247
 2,381
 19
 2,400
New York512
 7
 519
 541
 8
 549
800
 10
 810
 832
 9
 841
ERCOT178
 (24) 154
 235
 (117) 118
252
 (27) 225
 396
 (180) 216
Other Power Regions328
 (36) 292
 511
 (87) 424
542
 (64) 478
 740
 (133) 607
Total Revenues net of purchased power and fuel expense for Reportable Segments3,848

(49)
3,799

4,462

(154)
4,308
5,870

(87)
5,783

6,652

(240)
6,412
Other(b)
161
 49
 210
 55
 154
 209
262
 87
 349
 164
 240
 404
Total Generation Revenues net of purchased power and fuel expense$4,009

$—

$4,009

$4,517

$—

$4,517
$6,132

$—

$6,132

$6,816

$—

$6,816
__________
(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 unrealized mark-to-market losses of $102$84 million and $175$104 million in 2019 and 2018, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of $9$13 million and $34$53 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

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


Note 18 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):
 Nine Months Ended September 30, 2019
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$2,221
 $1,231
 $1,019
 $1,816
 $792
 $499
 $525
Small commercial & industrial1,103
 304
 193
 387
 114
 141
 132
Large commercial & industrial399
 163
 335
 843
 633
 75
 135
Public authorities & electric railroads35
 23
 20
 47
 27
 10
 10
Other(a)
660
 186
 242
 481
 166
 151
 164
Total rate-regulated electric revenues(b)
4,418
 1,907
 1,809
 3,574
 1,732
 876
 966
Rate-regulated natural gas revenues             
Residential—
 285
 327
 64
 —
 64
 —
Small commercial & industrial—
 122
 55
 30
 —
 30
 —
Large commercial & industrial—
 1
 93
 4
 —
 4
 —
Transportation—
 18
 —
 11
 —
 11
 —
Other(c)
—
 5
 19
 6
 —
 6
 —
Total rate-regulated natural gas revenues(d)
—
 431
 494
 115
 —
 115
 —
Total rate-regulated revenues from contracts with customers4,418
 2,338
 2,303
 3,689
 1,732
 991
 966
              
Other revenues             
Revenues from alternative revenue programs(98) (16) 11
 4
 10
 (6) —
Other rate-regulated electric revenues(e)
22
 10
 10
 7
 6
 1
 —
Other rate-regulated natural gas revenues(e)
—
 1
 3
 —
 —
 1
 —
Total other revenues(76) (5) 24
 11
 16
 (4) —
Total rate-regulated revenues for reportable segments$4,342
 $2,333
 $2,327
 $3,700
 $1,748
 $987
 $966
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Electric and Gas Revenue by Customer Class (Utility Registrants):
 Six Months Ended June 30, 2019
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$1,356
 $752
 $667
 $1,073
 $480
 $320
 $273
Small commercial & industrial709
 195
 129
 241
 73
 93
 75
Large commercial & industrial259
 100
 219
 545
 411
 49
 85
Public authorities & electric railroads23
 14
 13
 31
 17
 7
 7
Other(a)
442
 123
 160
 317
 108
 101
 108
Total rate-regulated electric revenues(b)
2,789
 1,184
 1,188
 2,207
 1,089
 570
 548
Rate-regulated natural gas revenues             
Residential—
 247
 279
 55
 —
 55
 —
Small commercial & industrial—
 105
 46
 26
 —
 26
 —
Large commercial & industrial—
 1
 73
 3
 —
 3
 —
Transportation—
 13
 —
 7
 —
 7
 —
Other(c)
—
 3
 13
 4
 —
 4
 —
Total rate-regulated natural gas revenues(d)
—
 369
 411
 95
 —
 95
 —
Total rate-regulated revenues from contracts with customers2,789
 1,553
 1,599
 2,302
 1,089
 665
 548
              
Other revenues             
Revenues from alternative revenue programs(42) (6) 17
 12
 13
 1
 (1)
Other rate-regulated electric revenues(e)
12
 7
 6
 5
 4
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 3
 —
 —
 —
 —
Total other revenues(30) 1
 26
 17
 17
 2
 (1)
Total rate-regulated revenues for reportable segments$2,759
 $1,554
 $1,625
 $2,319
 $1,106
 $667
 $547

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 18 — (Continued)
(Dollars in millions, except per share data, unless otherwise noted) Segment Information

Six Months Ended June 30, 2018Nine Months Ended September 30, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACEComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues                          
Residential$1,416
 $741
 $688
 $1,114
 $486
 $333
 $295
$2,277
 $1,199
 $1,054
 $1,839
 $792
 $513
 $534
Small commercial & industrial741
 198
 128
 230
 65
 90
 75
1,132
 306
 196
 370
 104
 138
 128
Large commercial & industrial280
 110
 207
 541
 402
 48
 91
411
 174
 325
 845
 632
 74
 139
Public authorities & electric railroads25
 14
 14
 30
 16
 7
 7
36
 21
 21
 44
 24
 10
 10
Other(a)
444
 122
 156
 289
 98
 82
 110
656
 181
 246
 446
 145
 129
 174
Total rate-regulated electric revenues(b)
2,906
 1,185
 1,193
 2,204
 1,067
 560
 578
4,512
 1,881
 1,842
 3,544
 1,697
 864
 985
Rate-regulated natural gas revenues                          
Residential—
 223
 298
 60
 —
 60
 —
—
 259
 345
 68
 —
 68
 —
Small commercial & industrial—
 87
 47
 26
 —
 26
 —
—
 102
 55
 31
 —
 31
 —
Large commercial & industrial—
 1
 70
 5
 —
 5
 —
—
 1
 88
 7
 —
 7
 —
Transportation—
 11
 —
 9
 —
 9
 —
—
 16
 —
 12
 —
 12
 —
Other(c)
—
 3
 40
 6
 —
 6
 —
—
 4
 49
 11
 —
 11
 —
Total rate-regulated natural gas revenues(d)
—
 325
 455
 106
 —
 106
 —
—
 382
 537
 129
 —
 129
 —
Total rate-regulated revenues from contracts with customers2,906
 1,510
 1,648
 2,310
 1,067
 666
 578
4,512
 2,263
 2,379
 3,673
 1,697
 993
 985
                          
Other revenues                          
Revenues from alternative revenue programs(12) 1
 (17) 12
 10
 5
 (3)(27) 2
 (23) 7
 6
 5
 (4)
Other rate-regulated electric revenues(e)
16
 7
 6
 5
 3
 2
 —
23
 10
 10
 8
 5
 3
 —
Other rate-regulated natural gas revenues(e)
—
 —
 2
 —
 —
 —
 —
—
 —
 3
 —
 —
 —
 —
Total other revenues4
 8
 (9) 17
 13
 7
 (3)(4) 12
 (10) 15
 11
 8
 (4)
Total rate-regulated revenues for reportable segments$2,910
 $1,518
 $1,639
 $2,327
 $1,080
 $673
 $575
$4,508
 $2,275
 $2,369
 $3,688
 $1,708
 $1,001
 $981

__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $9$13 million, $2$4 million, $1$5 million, $7$11 million, $3$5 million, $3$5 million and $1$2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $19$23 million, $3$5 million, $3$5 million, $7$11 million $3$5 million, $4$6 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of less than $1 million and $9$13 million at PECO and BGE respectively, in 2019 and less than $1 million and $9 million at PECO and BGE, respectively, in 2018, respectively.
(e)Includes late payment charge revenues.


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 is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.
Exelon has eleven reportable segments consisting of Generation’sGeneration���s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL and ACE. During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation disclosed five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. See Note 1 — Significant Accounting Policies and Note 18 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.

Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018. For additional information regarding the financial results for the three and sixnine months ended JuneSeptember 30, 2019 and 2018 see the discussions of Results of Operations by Registrant.
Three Months Ended June 30, Favorable (unfavorable) variance Six Months Ended June 30, Favorable (unfavorable) varianceThree Months Ended September 30, Favorable (unfavorable) variance Nine Months Ended September 30, Favorable (unfavorable) variance
2019 2018 2019 2018 2019 2018 2019 2018 
Exelon484
 539
 $(55) $1,391
 $1,125
 $266
772
 733
 $39
 $2,164
 $1,858
 $306
Generation108
 178
 (70) 472
 314
 158
257
 234
 23
 728
 547
 181
ComEd186
 164
 22
 344
 329
 15
200
 193
 7
 544
 523
 21
PECO102
 96
 6
 270
 210
 60
140
 126
 14
 410
 336
 74
BGE45
 51
 (6) 206
 179
 27
55
 63
 (8) 261
 242
 19
PHI106
 84
 22
 223
 149
 74
189
 187
 2
 412
 336
 76
Pepco64
 54
 10
 119
 85
 34
98
 89
 9
 217
 174
 43
DPL30
 26
 4
 83
 57
 26
33
 33
 —
 116
 90
 26
ACE14
 8
 6
 24
 15
 9
63
 61
 2
 87
 76
 11
Other(a)
(63) (34) (29) (124) (56) (68)(69) (70) 1
 (191) (126) (65)
__________
(a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities.
Three Months Ended JuneSeptember 30, 2019 Compared to Three Months Ended JuneSeptember 30, 2018. Net income attributable to common shareholders deincreased by $55$39 million and diluted earnings per average common share decreasedincreased to $0.50$0.79 in 2019 from $0.56$0.76 in 2018 primarily due to:
Absence of accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO;
Decreased nuclear outage days in 2019;
Increased New York ZEC prices and the approval of the New Jersey ZEC program in the second quarter of 2019;
A benefit associated with the annual nuclear ARO update;
Decreased Operating and maintenance expense, which includes the impacts of previous cost management programs and lower pension and OPEB costs; and
Regulatory rate increases at PECO, BGE, Pepco, DPL and ACE.
The increases were partially offset by:
Lower capacity prices;
Lower mark-to-market gains;
Lower realized energy prices; and
Increased mark-to-market losses.Unfavorable weather conditions and volume at PECO.
The decreases were partially offset by:Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Net income attributable to common shareholders increased by $306 million and diluted earnings per average common share increased to $2.22 in 2019 from $1.92 in 2018 primarily due to:

Higher net unrealized and realized gains on NDT Funds;funds;
Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018;
Increased New York ZEC prices2018 and the approvalabsence of a charge associated with the New Jersey ZEC Program in the second quarter of 2019; and
Regulatory rate increases at PECO, BGE, Pepco, DPL and ACE.
Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018.Net income attributable to common shareholders increased by $266 million and diluted earnings per average common share increased to $1.43 in 2019 from $1.16 in 2018 primarily due to:
Higher net unrealized and realized gains on NDT Funds;
Decreased accelerated depreciation and amortization due to the early retirementremeasurement of the Oyster Creek ARO;
Decreased Operating and maintenance expense which includes the impacts of previous cost management programs and lower pension and OPEB costs;
Decreased nuclear facilityoutage days in September 2018;2019;
A benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019 and the annual nuclear ARO update in the third quarter of 2019;
Decreased mark-to-market losses;

Regulatory rate increases at PECO, BGE, Pepco, DPL, and ACE; and
Decreased storms costs at PECO and BGE.
The increases were partially offset by:
Lower realized energy prices; and
Lower capacity prices;
The absence of the revenues recognized in the first quarter of 2018 related to ZECs generated in Illinois from June through December 2017, partially offset by increased New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019.2019;
Higher mark-to-market losses; and
Unfavorable weather conditions and volume at PECO.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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 sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018.
 Three Months Ended June 30,
 2019 2018
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$484
 $0.50
 $539
 $0.56
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $22 and $23, respectively)
68
 0.07
 (67) (0.07)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $28 and $77, respectively)(a)
52
 0.05
 81
 0.08
PHI Merger and Integration Costs (net of taxes of $0)
—
 —
 1
 —
Long-Lived Asset Impairments (net of taxes of $1 and $11, respectively)(b)
1
 —
 30
 0.03
Plant Retirements and Divestitures (net of taxes of $37 and $47, respectively)(c)
(24) (0.02) 127
 0.14
Cost Management Program (net of taxes of $1 and $4, respectively)(d)
6
 0.01
 12
 0.01
Change in Environmental Liabilities (net of taxes of $2)
—
 —
 5
 0.01
Reassessment of Deferred Income Taxes (entire amount represents tax expense)(e)
—
 —
 (8) (0.01)
Litigation Settlement Gain (net of taxes of $7)(19) (0.02) —
 —
Noncontrolling Interests (net of taxes of $3 and $7, respectively)(f)
15
 0.02
 (34) (0.04)
Adjusted (non-GAAP) Operating Earnings$583
 $0.60
 $686
 $0.71
 Three Months Ended September 30,
 2019 2018
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$772
 $0.79
 $733
 $0.76
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $2 and $20, respectively)
(2) —
 (55) (0.06)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $34 and $4, respectively)(a)
(39) (0.04) (53) (0.06)
Asset Impairments (net of taxes of $53 and $2, respectively)(b)
113
 0.12
 6
 0.01
Plant Retirements and Divestitures (net of taxes of $40 and $70, respectively)(c)
119
 0.12
 202
 0.21
Cost Management Program (net of taxes of $3 and $4, respectively)(d)
14
 0.01
 13
 0.01
Asset Retirement Obligation(e) (net of taxes of $9 and $6, respectively)
(84) (0.09) 16
 0.02
Change in Environmental Liabilities (net of taxes of $5 and $3, respectively)
18
 0.02
 (9) (0.01)
Income Tax-Related Adjustments (entire amount represents tax expense)(f)
13
 0.01
 (18) (0.02)
Noncontrolling Interests (net of taxes of $3 and $4, respectively)(g)
(24) (0.02) 21
 0.02
Adjusted (non-GAAP) Operating Earnings$900
 $0.92
 $856
 $0.88

 Six Months Ended June 30,
 2019 2018
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$1,391
 $1.43
 $1,125
 $1.16
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $34 and $46, respectively)98
 0.10
 129
 0.13
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $133 and $122, respectively)(a)
(142) (0.15) 147
 0.15
PHI Merger and Integration Costs (net of taxes of $2)
—
 —
 4
 

Long-Lived Asset Impairments (net of taxes of $2 and $11, respectively)(b)
6
 0.01
 30
 0.03
Plant Retirements and Divestitures (net of taxes of $32 and $78, respectively)(c)
(4) —
 220
 0.23
Cost Management Program (net of taxes of $7 and $6, respectively)(d)
16
 0.02
 16
 0.02
Change in Environmental Liabilities (net of taxes of $2)
—
 —
 5
 0.01
Reassessment of Deferred Income Taxes (entire amount represents tax expense)(e)
—
 —
 (8) (0.01)
Litigation Settlement Gain (net of taxes of $7)(19) (0.02) —
 —
Noncontrolling Interests (net of taxes of $15 and $13, respectively)(f)
82
 0.08
 (57) (0.06)
Adjusted (non-GAAP) Operating Earnings$1,429
 $1.47
 $1,611
 $1.66
 Nine Months Ended September 30,
 2019 2018
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$2,164
 $2.22
 $1,858
 $1.92
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $31 and $26, respectively)97
 0.10
 74
 0.08
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $167 and $118, respectively)(a)
(181) (0.19) 94
 0.10
PHI Merger and Integration Costs (net of taxes of $1)
—
 —
 5
 —
Asset Impairments (net of taxes of $54 and $13, respectively)(b)
119
 0.12
 36
 0.04
Plant Retirements and Divestitures (net of taxes of $9 and $148, respectively)(c)
114
 0.12
 422
 0.43
Cost Management Program (net of taxes of $10 and $10, respectively)(d)
31
 0.03
 29
 0.03
Litigation Settlement Gain (net of taxes of $7)(19) (0.02) —
 —
Asset Retirement Obligation (net of taxes of $9 and $6, respectively)(e)
(84) (0.09) 16
 0.02
Change in Environmental Liabilities (net of taxes of $5 and $1, respectively)
18
 0.02
 (4) —
Income Tax-Related Adjustments (entire amount represents tax expense)(f)
13
 0.01
 (27) (0.03)
Noncontrolling Interests (net of taxes of $18 and $9, respectively)(g)
58
 0.06
 (36) (0.04)
Adjusted (non-GAAP) Operating Earnings$2,329
 $2.39
 $2,467
 $2.55
__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2019 and 2018 ranged from 26.0 percent to 29.0 percent. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 35.147.1 percent and 48.97.7 percent for the three months ended JuneSeptember 30, 2019 and 2018, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 48.448.1 percent and 45.355.5 percent for the sixnine months ended JuneSeptember 30, 2019 and 2018, respectively.

(a)Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.
(b)In 2018, primarily reflects the impairment of certain wind projects at Generation. In 2019, primarily reflects the impairment of equity method investments in certain distributed energy companies.
(c)
In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek and TMI nuclear facility, as well as accelerated depreciation and amortization expensesfacilities, a charge associated with a remeasurement of the 2017 decision to early retire the Three Mile Island nuclear facility,Oyster Creek ARO, partially offset by a gain associated with Generation's sale of its electrical contracting business. In 2019, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and certain fossil sites and the loss on the sale of Oyster Creek to Holtec, partially offset by net realized gains related to Oyster Creek's NDT fund investments, in conjunction with the Holtec sale on July 1, 2019, a net benefit associated with a remeasurement in the first quarter 2019remeasurements of the TMI asset retirement obligationARO and a gain on the sale of certain wind assets in the second quarter of 2019, partially offset by accelerated depreciation and amortization expenses associated with Generation's previous decision to early retire the TMI nuclear facility.
assets.
(d)Primarily represents reorganization costs related to cost management programs.
(e)Reflects
In 2018, reflects an increase at Pepco related primarily to asbestos identified at its Buzzard Point property. In 2019, reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.
(f)In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA. In 2019, primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.
(f)(g)Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items,items. In 2018, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.for CENG units. In 2019, primarily related to

the impact of unrealized gains on NDT fund investments and the impact of the Generation's annual nuclear ARO update for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies.
Significant 2019 Transactions and Developments
Cost Management Programs
Exelon continues to be committed to managing its costs. On October 31, 2019, Exelon announced additional annual cost savings of approximately $100 million, at Generation, to be achieved by 2022. These actions are in response to the continuing economic challenges confronting Generation’s business, necessitating continued focus on cost management through enhanced efficiency and productivity.
Conowingo Hydroelectric Project
In connection with Generation’s pursuit of a new FERC license for Conowingo, on October 29, 2019, Generation and MDE entered into a settlement agreement that would resolve all outstanding issues between the parties, effective upon and subject to FERC’s approval and incorporation of the terms into the new license when issued. The financial impact of this settlement, along with other anticipated and prior license commitments, would be recognized over the term of the new 50-year license and is estimated to be, on average, $11 million to $14 million per year, including capital and operating costs. The actual timing and amount of a majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license.
Utility Rates and Base Rate Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2019. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateRequested Revenue Requirement (Decrease) IncreaseApproved Revenue Requirement (Decrease) IncreaseApproved ROEApproval DateRate Effective DateFiling DateRequested Revenue Requirement (Decrease) IncreaseApproved Revenue Requirement (Decrease) IncreaseApproved ROEApproval DateRate Effective Date
ComEd - Illinois (Electric)April 16, 2018$(23)$(24)8.69%December 4, 2018January 1, 2019April 16, 2018$(23)$(24)8.69%December 4, 2018January 1, 2019
PECO - Pennsylvania (Electric)March 29, 2018$82
$25
N/ADecember 20, 2018January 1, 2019March 29, 2018$82
$25
N/A
December 20, 2018January 1, 2019
BGE - Maryland (Natural Gas)June 8, 2018 (amended October 12, 2018)$61
$43
9.8%January 4, 2019June 8, 2018 (amended October 12, 2018)$61
$43
9.8%January 4, 2019January 4, 2019
ACE - New Jersey (Electric)August 21, 2018 (amended November 19, 2018)$122
$70
9.6%March 13, 2019April 1, 2019August 21, 2018 (amended November 19, 2018)$122
$70
9.6%March 13, 2019April 1, 2019
Pepco - Maryland (Electric)January 15, 2019 (amended May 16, 2019)$27
$10
9.6%August 12, 2019August 13, 2019

Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateRequested Revenue Requirement Increase (Decrease)Requested ROEExpected Approval TimingFiling DateRequested Revenue Requirement (Decrease) IncreaseRequested ROEExpected Approval Timing
Pepco - Maryland (Electric)January 15, 2019 (amended May 16, 2019)$27
10.3%Third quarter of 2019
ComEd - Illinois (Electric)April 8, 2019$(6)8.91%December 2019April 8, 2019$(6)8.91%December 2019
BGE - Maryland (Electric)May 24, 2019$74
10.3%December 2019
BGE - Maryland (Natural Gas)May 24, 2019$59
10.3%December 2019
BGE - Maryland (Electric)(a)
May 24, 2019 (amended October 4, 2019)$74
10.3%December 2019
BGE - Maryland (Natural Gas)(a)
May 24, 2019 (amended October 4, 2019)$59
10.3%December 2019
Pepco - District of Columbia (Electric)May 30, 2019$162
10.3%Second quarter of 2020May 30, 2019 (amended September 16, 2019)$160
10.3%Fourth quarter of 2020

__________
(a)
On October 25, 2019, BGE filed a settlement agreement with the MDPSC. The settlement provides for an increase to BGE’s annual electric and natural gas distribution rates of $18 million and $45 million, respectively.
Transmission Formula Rate
The following total increases/(decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2019 annual electric transmission formula rate updates.
RegistrantInitial Revenue Requirement Increase (Decrease)Annual Reconciliation Increase (Decrease)Total Revenue Requirement Increase (Decrease)Allowed Return on Rate BaseAllowed ROEInitial Revenue Requirement Increase (Decrease)Annual Reconciliation Increase (Decrease)Total Revenue Requirement Increase (Decrease)Allowed Return on Rate BaseAllowed ROE
ComEd$21
$(16)$5
8.21%11.50%21
(16)5
8.21%11.50%
BGE(10)(23)(19)7.35%10.50%(10)(23)(19)7.35%10.50%
Pepco15
11
26
7.75%10.50%15
11
26
7.75%10.50%
DPL17
(1)16
7.14%10.50%17
(1)16
7.14%10.50%
ACE11
(2)9
7.79%10.50%11
(2)9
7.79%10.50%
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. PECO’s initial formula rate filing included a requested increase of  $22 million to PECO’s annual transmission revenue requirement, which reflected a ROE of  11%, inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures.
Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.
On July 22, 2019, PECO and other parties filed with FERC a settlement agreement, which includes a ROE of 10.35%, inclusive of a 50 basis point adder for being a member of a RTO. The settlement isdid not expected to have a material impact on PECO’s 2017, 2018, or 2019 annual transmission revenue requirements. A final order from FERC is not expected prior tobefore the fourthend of the first quarter of 2019.2020. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.

Early Plant Retirements and Divestitures
Oyster Creek. Generation permanently ceased generation operations at Oyster Creek inon September 17, 2018. On July 31, 2018, Generation entered into an agreement with Holtec International and its wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the sale and decommissioning of Oyster Creek. The sale was completed on July 1, 2019. Exelon and Generation expect therecognized a loss on the sale which will be recognized in the third quarter to be2019, which was immaterial. See Note 3 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Three Mile Island. On May 30, 2017, Generation announced it will permanently cease generationceased operations at TMI on or about September 30,20, 2019. As a result of the previous decision to early retire TMI, Exelon and Generation recorded a $75$113 million and $71$185 million incremental pre-tax net charge for the three and sixnine months ended JuneSeptember 30, 2019 primarily due to accelerated depreciation of the plant assets, partially offset by a benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019. For the full year ended December 31, 2019, Exelon and Generation estimate approximately $155 million of incremental pre-tax net non-cash charges associated with the early retirement of TMI, primarily due to accelerated depreciation of the plant assets.
Salem. In 2017, PSEG announced that its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest, were showing increased signs of economic distress, which could lead to an early retirement. PSEG is the operator of Salem and also has the decision makingdecision-making authority to retire Salem. In 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that

demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Assuming the continued effectiveness of the New Jersey ZEC program, Generation no longer considers Salem to be at heightened risk for early retirement.
Dresden, Byron and Braidwood. Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.
See Note 6 — Regulatory Matters, Note 8 — Early Plant Retirements and Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.
Pacific Gas & Electric Bankruptcy
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code. As of JuneSeptember 30, 2019, Generation had approximately $740$730 million and $500$495 million of net long-lived assets and nonrecourse debt outstanding, respectively, related to Antelope Valley. PG&E’s bankruptcy created an event of default for Antelope Valley’s nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the ongoing event of default and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of JuneSeptember 30, 2019.
In the first quarter of 2019, Generation assessed and determined that Antelope Valley’s long-lived assets were not impaired. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley's net long-lived assets, which could be material. Generation is monitoring the bankruptcy proceedings for any changes in circumstances that would indicate the carrying amount of the net long-lived assets of Antelope Valley may not be recoverable.
See Note 7 — Impairment of Long-Lived AssetsAsset Impairments and Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the PG&E bankruptcy.

Other Key Business Drivers and Management Strategies
The following discussion of other key business driver and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Key Business Drivers and Management Strategies in the Registrants' combined 2018 Form 10-K and Note 16 - Commitments and Contingencies to the Consolidated Financial Statements in this report for additional information on various environmental matters.
Power Markets
Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs
PJM and NYISO capacity markets include a 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

Jersey ZEC, 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 and are no different than other renewable support 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, an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions, which could have a material effect on Exelon’s and Generation’s future cash flows and results of operations.
In June 2018, FERC addressed one of the MOPR complaints involving PJM and concluded 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. FERC suggested that modifying two elements of PJM’s existing tariff, as follows could produce a just and reasonable replacement.
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.
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 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. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. On April 10, 2019, PJM notified FERC of its intent to proceed with the next capacity auction in August 2019 under the existing market rules and asked FERC to clarify that it would not require PJM to re-run the auction in the event FERC alters those market rules in its decision on the MOPR complaint. On July 25, 2019, FERC issued an order denying PJM’s request to clarify that any alteration of PJM’s existing market rules would operate prospectively and, therefore, directed PJM to not conduct the capacity auction in August 2019. 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.

Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps
On February 21, 2019, PJM’s Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM claims that this allows for the exercise of market power. The IMM asks FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation.
Section 232 Uranium Petition
On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce (DOC) seeking relief under Section 232 of the Trade Expansion Act of 1962, as amended, (the Act) from imports of uranium products, alleging that these imports threaten national security (the Petition). The relief requested would have required U.S. nuclear reactors to purchase at least 25% of their uranium needs from domestic mines for the next 10 years or more. The Act was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.

On July 18, 2018, the Secretary announced that the DOC had initiated an investigation in response to the petition. The Secretary submitted a report to President Trump on April 14, 2019 that has not been made public. On July 12, 2019, the President issued a memorandum indicating that he did not agree with the Secretary’s finding that uranium imports threaten to impair the national security of the United States, choosing not to impose any trade restrictions at this time. The President found that a fuller analysis of national security considerations with respect to the entire nuclear fuel supply chain is necessary and directed that a United States Nuclear Fuel Working Group (Working Group) be established to develop recommendations for reviving and expanding domestic nuclear fuel production with a mandate to submit a report back to him within 90 days. On October 10, 2019, the President granted a 30-day extension to the deadline for the Working Group to submit the report. The Working Group is to be co-chaired by the Assistant to the President for National Security Affairs and the Assistant to the President for Economic Policy. Exelon will monitor and volunteer to provide information to support the Working Group’s efforts. Exelon and Generation cannot currently predict the outcome of the Working Group report and subsequent actions.
Hedging Strategy
Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. As of JuneSeptember 30, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 92%-95%96%-99%, 70%-73%84%-87% and 40%-43%54%-57% for 2019, 2020, and 2021 respectively. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.
Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 62%63% of Generation’s uranium concentrate requirements from 2019 through 2023 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium 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 financial statements.

See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and Item 3. Quantitative and Qualitative Disclosures about Market Risk for additional information.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Environmental Legislative and Regulatory Developments
Air Quality
Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. In June 2019, EPA issued a final rule that repealed the CPP, and finalized the Affordable Clean Energy (ACE) rule to replace the CPP with less stringent emissions guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants.
Primary SO2 National Ambient Air Quality Standards (NAAQS). EPA took final action on April 17, 2019 to retain the current primary SO2 standard without revision, leaving the standard established in 2010 in effect.
See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to environmental matters, including the impact of environmental regulation.
Other Legislative and Regulatory Developments
Illinois Clean Energy Progress Act

On March 14, 2019, the Clean Energy Progress Act was introduced in the Illinois General Assembly to preserve Illinois’ clean energy choices arising from FEJA and empower the IPA to conduct capacity procurements outside of PJM’s base residual auction process, while utilizing the fixed resource requirement provisions in PJM's tariffs which are still subject to penalties and other obligations under the PJM tariffs. The most significant provisions of the proposed legislation are as follows: (1) it allows the IPA to procure capacity directly from clean energy resources that have previously sold ZECs or RECs, including certain of Generation’s nuclear plants in Illinois, or from new clean energy resources, (2) it establishes a goal of achieving 100% carbon-free power in the ComEd service territory by 2032, and (3) it implements reforms to enhance consumer protections in the state’s competitive retail electricity and natural gas markets, including Generation’s retail customers. Energy legislation has also been proposed by other stakeholders, including renewable resource developers, environmental advocates, and coal-fueled generators. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Keep Powering Pennsylvania Act
On March 11, 2019, the Keep Powering Pennsylvania Act was introduced in the Pennsylvania General Assembly to amend the Alternative Energy Portfolio Standards Act of 2004. The proposed legislation recognizes the value that all zero-emission electric generation resources provide to Pennsylvania by adding nuclear plants and certain other renewable generation resources (Tier III resources) to the zero-emission electric generation resources that currently receive alternative energy credits in Pennsylvania. Further, the proposed legislation would allow for these Tier III resources to continue to receive capacity payments at the same level as the PJM capacity auction clearing price. In order to initially qualify as a Tier III resource, a resource must make a commitment to operate for at least six years. The price of the alternative energy credits for Tier III resources is tied to the value of existing Tier I resources, with a price cap. Regulated utilities, including PECO, would be required to purchase alternative energy credits for all retail customers and allowed to recover those costs from customers. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Nuclear Powers Act of 2019
On April 12, 2019, the Nuclear Powers America Act of 2019 was introduced to the United States Congress, which expands the current investment tax credit to existing nuclear power plants. The proposed legislation would provide

a credit equal to 30% of continued capital investment in certain nuclear energy-related expenditures, including capital expenses and nuclear fuel, starting from tax years 2019 through 2023. Thereafter, the credit rate would be reduced to 26% in 2024, 22% in 2025, and 10% in 2026 and beyond. To qualify for the credit, the plant must be currently operational and must have applied for an operating license renewal before 2026.  Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Employees
In April 2019, the CBAs with IBEW Local 15 covering employees at BSC, ComEd and Generation, were extended through 2024. The CBA between Pepco and IBEW Local 1900 was scheduled to expire on May 26, 2019, but has been extended to September 7, 2019. OnIn June 23, 2019, BGE’s union contract for theapproximately 1,400 employees within localLocal 410 was ratified. BGE is now in the process of implementing its terms,ratified, which dodid not have a material impact on BGE's financial statements. In July 2019, the CBA between Generation and the Security Officer’s union at Byron, which was scheduled to expire on September 30, 2019, was extended to December 31, 2019. In September 2019, negotiations completed between Pepco and IBEW Local 1900 and the CBA will expire in 2022. In September 2019, the CBA between Generation and Local 614 at Conowingo, Eddystone and Fairless Hills stations, which was scheduled to expire on November 3, 2019, was extended to March 3, 2020.
Critical Accounting Policies and Estimates
Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. At JuneSeptember 30, 2019, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2018. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — CRITICAL ACCOUNTING POLICIES AND ESTIMATESCritical Accounting Policies and Estimates in the Registrants' 2018 Form 10-K for further information.

Results of Operations by Registrant
The Registrants' Results of Operations includes discussion of RNF, which is a financial measure not defined under GAAP and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. The CODMs for Exelon and Generation evaluate the performance of Generation's electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measure because it provides information that can be used to evaluate its operational performance. For the Utility Registrants, their Operating revenues reflect the full and current recovery of commodity procurement costs given the rider mechanisms approved by their respective state regulators. The commodity procurement costs, which are recorded in Purchased power and fuel expense, and the associated revenues can be volatile. Therefore, the Utility Registrants believe that RNF is a useful measure because it excludes the effect on Operating revenues caused by the volatility in these expenses.

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Results of Operations — Generation
Three Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 Six Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
2019 2018 2019 2018 2019 2018 2019 2018 
Operating revenues$4,210
 $4,579
 $(369) $9,506
 $10,090
 $(584)$4,774
 $5,278
 $(504) $14,280
 $15,368
 $(1,088)
Purchased power and fuel expense2,292
 2,280
 (12) 5,497
 5,573
 76
2,651
 2,980
 329
 8,148
 8,552
 404
Revenues net of purchased power and fuel expense1,918
 2,299
 (381) 4,009
 4,517
 (508)2,123
 2,298
 (175) 6,132
 6,816
 (684)
Other operating expenses                      
Operating and maintenance1,266
 1,418
 152
 2,484
 2,756
 272
1,087
 1,370
 283
 3,570
 4,126
 556
Depreciation and amortization409
 466
 57
 814
 914
 100
407
 468
 61
 1,221
 1,383
 162
Taxes other than income129
 134
 5
 264
 272
 8
129
 143
 14
 394
 414
 20
Total other operating expenses1,804
 2,018
 214
 3,562
 3,942
 380
1,623
 1,981
 358
 5,185
 5,923
 738
Gain on sales of assets and businesses33
 1
 32
 33
 54
 (21)
(Loss) gain on sales of assets and businesses(18) (6) (12) 15
 48
 (33)
Operating income147

282
 (135) 480

629
 (149)482

311
 171
 962

941
 21
Other income and (deductions)                      
Interest expense, net(116) (102) (14) (227) (202) (25)(109) (101) (8) (336) (305) (31)
Other, net171
 29
 142
 601
 (15) 616
128
 179
 (51) 729
 164
 565
Total other income and (deductions)55
 (73) 128
 374
 (217) 591
19
 78
 (59) 393
 (141) 534
Income before income taxes202
 209
 (7) 854
 412
 442
501
 389
 112
 1,355
 800
 555
Income taxes78
 23
 (55) 301
 32
 (269)87
 78
 (9) 388
 110
 (278)
Equity in losses of unconsolidated affiliates(6) (5) (1) (13) (12) (1)(170) (11) (159) (183) (23) (160)
Net income118

181

(63)
540

368

172
244

300

(56)
784

667

117
Net income attributable to noncontrolling interests10
 3
 (7) 68
 54
 (14)
Net (loss) income attributable to noncontrolling interests(13) 66
 79
 56
 120
 64
Net income attributable to membership interest$108
 $178
 $(70) $472
 $314
 $158
$257
 $234
 $23
 $728
 $547
 $181
Three Months Ended JuneSeptember 30, 2019 Compared to Three Months Ended JuneSeptember 30, 2018. Net income attributable to membership interest decreasedincreased by $70$23 million primarily due to:
Lower realized energy prices; and
Increased mark-to-market losses.
The decreases were partially offset by:
Higher net unrealized and realized gains on NDT funds;
DecreasedAbsence of accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018;2018 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO;
Decreased nuclear outage days in 2019;
Increased New York ZEC prices and the approval of the New Jersey ZEC Programprogram in the second quarter of 2019.2019;

A benefit associated with the annual nuclear ARO update; and
Decreased Operating and maintenance expense, which includes the impacts of previous cost management programs and lower pension and OPEB costs.
147The increases were partially offset by:
Lower capacity prices;

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Lower mark-to-market gains; and
Lower realized energy prices.
SixNine Months Ended JuneSeptember 30, 2019 Compared to SixNine Months Ended JuneSeptember 30, 2018. Net income attributable to membership interest increased by $158$181 million primarily due to:
Higher net unrealized and realized gains on NDT funds;
Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018;2018 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO;
Decreased Operating and maintenance expense which includes the impacts of previous cost management programs and lower pension and OPEB costs;
Decreased nuclear outage days in 2019; and
A benefit associated with the remeasurement of the TMI ARO in 2019;the first quarter of 2019 and
Decreased mark-to-market losses. the annual nuclear ARO update in the third quarter of 2019.
The increases were partially offset by:
Lower realized energy prices; and
Lower capacity prices;
The absence of the revenues recognized in the first quarter of 2018 related to ZECs generated in Illinois from June through December 2017, partially offset by increased New York ZEC prices and the approval of the New Jersey ZECsZEC Program in the second quarter of 2019.2019; and
Higher mark-to-market losses.
Revenues Net of Purchased Power and Fuel Expense. The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned with these same geographic regions. Generation's five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. See Note 24 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information.
The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall operating revenues or results of operations. Further, the following activities are not allocated to a region and are reported in Other: accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.
Generation evaluates the operating performance of electric business activities using the measure of RNF. Operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.

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For the three and sixnine months ended JuneSeptember 30, 2019 and 2018, RNF by region were as follows:
Three Months Ended
June 30,		 Variance % Change Six Months Ended
June 30,		 Variance % ChangeThree Months Ended
September 30,		 Variance % Change Nine Months Ended
September 30,		 Variance % Change
2019 2018 2019 2018 2019 2018 2019 2018 
Mid-Atlantic(a)
$652
 $735
 $(83) (11.3)% $1,334
 $1,586
 $(252) (15.9)%$689
 $763
 $(74) (9.7)% $2,023
 $2,348
 $(325) (13.8)%
Midwest(b)
730
 772
 (42) (5.4)% 1,500
 1,631
 (131) (8.0)%747
 768
 (21) (2.7)% 2,247
 2,400
 (153) (6.4)%
New York253
 266
 (13) (4.9)% 519
 549
 (30) (5.5)%291
 292
 (1) (0.3)% 810
 841
 (31) (3.7)%
ERCOT79
 82
 (3) (3.7)% 154
 118
 36
 30.5 %72
 98
 (26) (26.5)% 225
 216
 9
 4.2 %
Other Power Regions134
 186
 (52) (28.0)% 292
 424
 (132) (31.1)%184
 180
 4
 2.2 % 478
 607
 (129) (21.3)%
Total electric revenue net of purchased power and fuel expense1,848
 2,041
 (193) (9.5)% 3,799
 4,308
 (509) (11.8)%1,983
 2,101
 (118) (5.6)% 5,783
 6,412
 (629) (9.8)%
Proprietary Trading7
 29
 (22) (75.9)% 11
 35
 (24) (68.6)%(1) 5
 (6) (120.0)% 10
 39
 (29) (74.4)%
Mark-to-market gains (losses)(74) 90
 (164) (182.2)% (102) (175) 73
 (41.7)%17
 71
 (54) (76.1)% (84) (104) 20
 (19.2)%
Other137
 139
 (2) (1.4)% 301
 349
 (48) (13.8)%124
 121
 3
 2.5 % 423
 469
 (46) (9.8)%
Total revenue net of purchased power and fuel expense$1,918
 $2,299
 $(381) (16.6)% $4,009
 $4,517
 $(508) (11.2)%$2,123
 $2,298
 $(175) (7.6)% $6,132
 $6,816
 $(684) (10.0)%
_________
(a)Includes results of transactions with PECO, BGE, Pepco, DPL and ACE.
(b)Includes results of transactions with ComEd.

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Generation’s supply sources by region are summarized below:
Three Months Ended
June 30,		 Variance % Change Six Months Ended
June 30,		 Variance % ChangeThree Months Ended
September 30,		 Variance % Change Nine Months Ended
September 30,		 Variance % Change
Supply source (GWhs)2019 2018 2019 2018 2019 2018 2019 2018 
Nuclear Generation(a)
                              
Mid-Atlantic14,075
 16,498
 (2,423) (14.7)% 29,155
 32,727
 (3,572) (10.9)%15,281
 16,197
 (916) (5.7)% 44,436
 48,924
 (4,488) (9.2)%
Midwest23,996
 23,100
 896
 3.9 % 47,729
 46,698
 1,031
 2.2 %23,730
 23,834
 (104) (0.4)% 71,459
 70,532
 927
 1.3 %
New York6,677
 6,125
 552
 9.0 % 13,579
 13,239
 340
 2.6 %7,204
 6,518
 686
 10.5 % 20,783
 19,758
 1,025
 5.2 %
Total Nuclear Generation44,748
 45,723
 (975) (2.1)% 90,463

92,664
 (2,201) (2.4)%46,215
 46,549
 (334) (0.7)% 136,678

139,214
 (2,536) (1.8)%
Fossil and Renewables            

 

            

 

Mid-Atlantic915
 907
 8
 0.9 % 1,865
 1,807
 58
 3.2 %485
 853
 (368) (43.1)% 2,351
 2,660
 (309) (11.6)%
Midwest328
 321
 7
 2.2 % 719
 776
 (57) (7.3)%262
 244
 18
 7.4 % 981
 1,020
 (39) (3.8)%
New York1
 1
 —
 — % 2
 2
 —
 — %3
 1
 2
 200.0 % 4
 3
 1
 33.3 %
ERCOT3,066
 2,303
 763
 33.1 % 6,144
 5,252
 892
 17.0 %4,500
 3,137
 1,363
 43.4 % 10,644
 8,389
 2,255
 26.9 %
Other Power Regions2,514
 3,037
 (523) (17.2)% 5,654
 7,065
 (1,411) (20.0)%3,135
 3,628
 (493) (13.6)% 8,789
 10,692
 (1,903) (17.8)%
Total Fossil and Renewables6,824
 6,569
 255
 3.9 % 14,384

14,902
 (518) (3.5)%8,385
 7,863
 522
 6.6 % 22,769

22,764
 5
 — %
Purchased Power            

 

            

 

Mid-Atlantic2,557
 557
 2,000
 359.1 % 5,123
 1,323
 3,800
 287.2 %5,235
 3,504
 1,731
 49.4 % 10,359
 4,828
 5,531
 114.6 %
Midwest250
 223
 27
 12.1 % 538
 559
 (21) (3.8)%124
 174
 (50) (28.7)% 662
 733
 (71) (9.7)%
ERCOT1,213
 2,320
 (1,107) (47.7)% 2,255
 3,692
 (1,437) (38.9)%1,329
 1,811
 (482) (26.6)% 3,585
 5,504
 (1,919) (34.9)%
Other Power Regions11,116
 10,455
 661
 6.3 % 23,684
 20,025
 3,659
 18.3 %13,006
 12,705
 301
 2.4 % 36,693
 32,731
 3,962
 12.1 %
Total Purchased Power15,136
 13,555
 1,581
 11.7 % 31,600

25,599
 6,001
 23.4 %19,694
 18,194
 1,500
 8.2 % 51,299

43,796
 7,503
 17.1 %
Total Supply/Sales by Region            

 

            

 

Mid-Atlantic(b)
17,547
 17,962
 (415) (2.3)% 36,143
 35,857
 286
 0.8 %21,001
 20,554
 447
 2.2 % 57,146
 56,412
 734
 1.3 %
Midwest(b)
24,574
 23,644
 930
 3.9 % 48,986
 48,033
 953
 2.0 %24,116
 24,252
 (136) (0.6)% 73,102
 72,285
 817
 1.1 %
New York6,678
 6,126
 552
 9.0 % 13,581
 13,241
 340
 2.6 %7,207
 6,519
 688
 10.6 % 20,787
 19,761
 1,026
 5.2 %
ERCOT4,279
 4,623
 (344) (7.4)% 8,399
 8,944
 (545) (6.1)%5,829
 4,948
 881
 17.8 % 14,229
 13,893
 336
 2.4 %
Other Power Regions13,630
 13,492
 138
 1.0 % 29,338
 27,090
 2,248
 8.3 %16,141
 16,333
 (192) (1.2)% 45,482
 43,423
 2,059
 4.7 %
Total Supply/Sales by Region66,708
 65,847
 861
 1.3 % 136,447

133,165
 3,282
 2.5 %74,294
 72,606
 1,688
 2.3 % 210,746

205,774
 4,972
 2.4 %
_________
(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)Includes affiliate sales to PECO, BGE, Pepco, DPL and BGEACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region and affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region.

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Generation

For the three and sixnine months ended JuneSeptember 30, 2019 and 2018, changes in RNF by region were as follows:
Increase/ (Decrease)Three Months Ended
June 30, 2019		Increase/ (Decrease)Six Months Ended
June 30, 2019		Increase/ (Decrease)Three Months Ended
September 30, 2019		Increase/ (Decrease)Nine Months Ended
September 30, 2019
Mid-Atlantic$(83)
• decreased revenue due to permanent cease of generation operations at Oyster Creek in Q3 2018
• lower realized energy prices
• increased nuclear outage days primarily related to Salem
$(252)
• lower realized energy prices
• decreased revenue due to permanent cease of generation operations at Oyster Creek in Q3 2018
• increased nuclear outage days primarily related to Salem, partially offset by
• increased capacity prices
$(74)
• decreased capacity prices
• decreased revenue due to permanent cease of generation operations at Oyster Creek in Q3 2018
• lower realized energy prices, partially offset by
• increased ZEC revenues due to the approval of the NJ ZEC program in Q2 2019

$(325)
• lower realized energy prices
• decreased revenue due to permanent cease of generation operations at Oyster Creek in Q3 2018
• increased nuclear outage days primarily at Salem
• decreased capacity prices, partially offset by
• increased ZEC revenues due to the approval of the NJ ZEC program in Q2 2019
Midwest(42)
• lower realized energy prices, partially offset by
• decreased nuclear outage days

(131)
• the absence of the revenue recognized in the first quarter 2018 related to ZECs generated in Illinois from June through December 2017
• lower realized energy prices, partially offset by
• increased capacity prices and
• decreased nuclear outage days
(21)
• decreased capacity prices partially offset by
• higher realized energy prices


(153)
• the absence of the revenue recognized in the first quarter 2018 related to ZECs generated in Illinois from June through December 2017, partially offset by
• higher realized energy prices and
• decreased nuclear outage days
New York(13)
• lower realized energy prices, partially offset by
• increased ZEC revenues due to higher ZEC prices
(30)
• lower realized energy prices, partially offset by
• increased ZEC revenues due to higher ZEC prices
(1)
• lower realized energy prices
• decreased capacity prices, partially offset by
• increased ZEC revenues due to higher ZEC prices and increased output at Fitzpatrick
• decreased nuclear outage days
(31)
• lower realized energy prices
• decreased capacity prices, partially offset by
• increased ZEC revenues due to higher ZEC prices and increased output at Fitzpatrick
• decreased nuclear outage days

ERCOT(3)• lower realized energy prices36
• higher realized energy prices(26)• decrease due to higher procurement costs for owned and contracted assets9
• higher realized energy prices, partially offset by
• higher procurements costs for owned and contracted assets
Other Power Regions(52)
• lower realized energy prices
• decreased capacity prices
(132)
• lower realized energy prices
• decreased capacity prices
4
• higher realized energy prices, partially offset by
• decreased capacity prices
(129)
• lower realized energy prices
• decreased capacity prices
Proprietary Trading(22)• congestion activity(24)• congestion activity(6)• congestion activity(29)• congestion activity
Mark-to-market(a)
(164)• losses on economic hedging activities of $74 million in 2019 compared to gains of $90 million in 201873
• losses on economic hedging activities of $102 million in 2019 compared to losses of $175 million in 2018(54)• gains on economic hedging activities of $17 million in 2019 compared to gains of $71 million in 201820
• losses on economic hedging activities of $84 million in 2019 compared to losses of $104 million in 2018
Other(2)• the impacts of declining natural gas prices(48)• the impacts of declining natural gas prices3
• no significant changes(46)
• the impacts of declining natural gas prices, partially offset by
• decrease in accelerated nuclear fuel amortization associated with announced early plant retirements
Total$(381) $(508) $(175) $(684) 
_________
(a)See Note 10 — Derivative Financial Instruments for additional information on mark-to-market losses.

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Generation

Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for the Generation-operated plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2019 2018 2019 2018
Nuclear fleet capacity factor95.1% 93.2% 96.1% 94.8%
Refueling outage days56
 94
 130
 162
Non-refueling outage days28
 2
 28
 8

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Generation

 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
Nuclear fleet capacity factor95.5% 93.6% 95.9% 94.4%
Refueling outage days15
 36
 145
 198
Non-refueling outage days15
 12
 43
 20
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting, materials(a)
$(30) $(60)$(77) $(135)
Nuclear refueling outage costs, including the co-owned Salem plants(22) (16)(35) (52)
Corporate allocations(18) (29)(12) (41)
Insurance(b)
1
 31
—
 31
Merger and integration costs(1) (5)—
 (5)
Plant retirements and divestitures(c)
15
 (87)(78) (164)
Change in environmental liabilities(7) (7)13
 6
Cost management program(8) —
Long-lived asset impairments(d)
(38) (33)
ARO update(d)
(66) (66)
Asset Impairments(e)
(6) (38)
Pension and non-pension postretirement benefits expense(17) (33)(11) (44)
Allowance for uncollectible accounts(6) (17)(1) (18)
Accretion expense(10) (17)(11) (28)
Other(11) 1
1
 (2)
Decrease in Operating and maintenance expense$(152) $(272)$(283) $(556)
_________ 
(a)Primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek, in the third quarter of 2018.lower labor costs resulting from previous cost management programs, and lower pension and OPEB costs.
(b)Primarily reflects the absence of a supplemental NEIL insurance distribution received in the first quarter of 2018.
(c)Primarily due to the benefit recorded in the first quarter of 2019 for the remeasurement of the TMI ARO.ARO and the absence of a charge associated with the remeasurement of the Oyster Creek ARO in the third quarter of 2018.
(d)Primarily reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.
(e)Primarily due to the impairment of certain wind projects recorded in the second quarter of 2018.
Depreciation and Amortization Expense for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 decreased primarily due to the permanent cease of generation operations at Oyster Creek in the third quarter of 2018.
Gain (Loss) on Sales of Assets and Businesses for the three months ended JuneSeptember 30, 2019 compared to the same period in 2018 increaseddecreased primarily due to Generation's sale of certain wind assets in the second quarter of 2019.Oyster Creek. Gain (loss) on sales of

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Generation

assets and businesses for the sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 decreased primarily due to Generation's sale of its electrical contracting business in the first quarter of 2018.

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Generation

Other, net for the three and six months ended JuneSeptember 30, 2019 compared to the same period in 2018 decreased and for the nine months ended September 30, 2019 compared to the same period in 2018 increased due to activity associated with NDT funds as described in the table below:
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2019 2018 2019 20182019 2018 2019 2018
Net unrealized gains (losses) on NDT funds(a)
$(98)
$(120) $182
 $(215)$55

$72
 $236
 $(143)
Net realized gains on sale of NDT funds(a)
193
 108
 222
 135
9
 29
 231
 164
Interest and dividend income on NDT funds(a)
36
 36
 61
 63
24
 29
 85
 93
Contractual elimination of income tax expense(b)

34
 3
 120
 (4)31
 29
 150
 24
Other6
 2
 16
 6
9
 20
 27
 26
Total other, net$171
 $29
 $601
 $(15)$128
 $179
 $729
 $164
_________ 
(a)Unrealized gains (losses), realized gains and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement units.
(b)Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement units.
Effective income tax rates were 38.6%17.4% and 11.0%20.1% for the three months ended JuneSeptember 30, 2019 and 2018, respectively. Generation's effective income tax rates were 35.2%28.6% and 7.8%13.8% for the sixnine months ended JuneSeptember 30, 2019 and 2018, respectively. The change is primarily related to a reduction in renewable tax credits and one-time tax adjustments. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Equity in losses of unconsolidated affiliates for the three and nine months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to the impairment of equity method investments in certain distributed energy companies.
153Net income attributable to noncontrolling interests for the three and nine months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to the offsetting noncontrolling interest impact of the impairment of equity method investments in certain distributed energy companies.

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ComEd

Results of Operations — ComEd
Three Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 Six Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
2019 2018 2019 2018 2019 2018 2019 2018 
Operating revenues$1,351
 $1,398
 $(47) $2,759
 $2,910
 $(151)$1,583
 $1,598
 $(15) $4,342
 $4,508
 $(166)
Purchased power expense407
 477
 70
 892
 1,082
 190
577
 619
 42
 1,469
 1,702
 233
Revenues net of purchased power expense944
 921
 23
 1,867
 1,828
 39
1,006
 979
 27
 2,873
 2,806
 67
Other operating expenses                      
Operating and maintenance305
 324
 19
 626
 638
 12
340
 337
 (3) 967
 974
 7
Depreciation and amortization257
 231
 (26) 508
 459
 (49)259
 237
 (22) 767
 696
 (71)
Taxes other than income71
 79
 8
 148
 156
 8
80
 82
 2
 228
 238
 10
Total other operating expenses633
 634
 1
 1,282
 1,253
 (29)679
 656
 (23) 1,962
 1,908
 (54)
Gain on sales of assets—
 1
 (1) 3
 5
 (2)1
 —
 1
 4
 5
 (1)
Operating income311
 288
 23
 588
 580
 8
328
 323
 5
 915
 903
 12
Other income and (deductions)                      
Interest expense, net(89) (85) (4) (178) (175) (3)(91) (85) (6) (268) (261) (7)
Other, net10
 4
 6
 19
 12
 7
8
 7
 1
 27
 21
 6
Total other income and (deductions)(79) (81) 2
 (159) (163) 4
(83) (78) (5) (241) (240) (1)
Income before income taxes232
 207
 25
 429
 417
 12
245
 245
 —
 674
 663
 11
Income taxes46
 43
 (3) 85
 88
 3
45
 52
 7
 130
 140
 10
Net income$186
 $164
 $22
 $344
 $329
 $15
$200
 $193
 $7
 $544
 $523
 $21
Three Months Ended JuneSeptember 30, 2019 Compared to Three Months Ended JuneSeptember 30, 2018. Net incomeremained relatively consistent for the three months ended JuneSeptember 30, 2019 increased $22 million as compared to the same period in 2018, primarily due to higher electric distribution, transmission and energy efficiency formula rate earnings(reflecting the impacts of higher rate base, partially offset by lower allowed electric distribution ROE due to a decrease in treasury rates).2018.
SixNine Months Ended JuneSeptember 30, 2019 Compared to SixNine Months Ended JuneSeptember 30, 2018. Net income for the six months ended June 30, 2019 increased $15$21 million as compared to the same period in 2018, primarily due to higher electric distribution, transmission and energy efficiency formula rate earnings (reflecting the impacts of higher rate base, partially offset by lower allowed electric distribution ROE due to a decrease in treasury rates). 
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC, and ZEC procurement costs and participation in customer choice programs. ComEd recovers electricity, REC, and ZEC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries but do impact Operating revenues related to supplied electricity.

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ComEd

The changes in RNF consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Electric distribution$12
 $37
$11
 $48
Transmission13
 22
5
 27
Energy efficiency14
 27
9
 36
Uncollectible accounts recovery, net(2) (2)(3) (5)
Other(14) (45)5
 (39)
Total increase$23
 $39
$27
 $67
Revenue Decoupling. The demand for electricity is affected by weather conditions and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer or number of customers as a result of a change to the electric distribution formula rate pursuant to FEJA.
Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased during the three and sixnine months ended JuneSeptember 30, 2019 as compared to the same period in 2018, primarily due to the impact of higher rate base and increased depreciation expenses, offset by lower allowed ROE due to a decrease in treasury rates. See Depreciation and amortization expense discussions below and Note 6 — Regulatory Matters.Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the three and six months ended JuneSeptember 30, 2019 as compared to the same period in 2018, primarily due to the impact of higher rate base and higher fully recoverable costs. Transmission revenue increased for the nine months ended September 30, 2019 as compared to the same period in 2018, primarily due to the impact of increased peak load, higher rate base, and higher rate base.fully recoverable costs. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the three and sixnine months ended JuneSeptember 30, 2019 as compared to the same period in 2018, primarily due to the impact of higher rate base.base and increased regulatory asset amortization. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Uncollectible Accounts Recovery, Net represents recoveries under the uncollectible accounts tariff. See Operating and maintenance expense discussion below for additional information on this tariff.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of environmental costs associated with MGP sites. Other revenue remained consistent for the three months ended September 30, 2019 as compared to the same period in 2018. The decrease in Other revenue for the three and sixnine months ended JuneSeptember 30, 2019 as compared to the same period in 2018 primarily reflects absence of mutual assistance revenues associated with hurricane and winter storm restoration efforts that occurred in Q1 2018. An equal and offsetting amount was included in Operating and maintenance expense and Taxes other than income.expense.
See Note 18 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

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ComEd

The decreasechanges in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Baseline      
Labor, other benefits, contracting and materials(a)
$—
 $(4)$—
 $(4)
Pension and non-pension postretirement benefits expense(b)
(9) (20)(8) (28)
Storm-related costs—
 18
7
 25
Uncollectible accounts expense — recovery, net(c)
(2) (2)(3) (5)
BSC costs(a)
(8) (7)12
 6
Other(a)
—
 3
(5) (1)
Total decrease$(19) $(12)
Total increase (decrease)$3
 $(7)
_________
(a)Reflects absence of mutual assistance expenses. An equal and offsetting decrease has been recognized in Operating revenues for the period presented.
(b)Primarily reflects an increase in discount rates and the favorable impacts of the merger of two of Exelon’s pension plans effective in January 2019, partially offset by lower than expected asset returns in 2018.
(c)ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. During the three and sixnine months ended JuneSeptember 30, 2019, 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 increase has been recognized in Operating revenues for the period presented.
The increasechanges in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase IncreaseIncrease Increase
Depreciation and amortization(a)
$17
 $32
$15
 $45
Regulatory asset amortization(b)
9
 17
7
 26
Total increase$26
 $49
$22
 $71
_________
(a)Reflects ongoing capital expenditures and higher depreciation rates effective January 2019.
(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Effective income tax rate was 19.8%18.4% and 20.8%21.2% for the three months ended JuneSeptember 30, 2019 and 2018, respectively. Effective income tax rate was 19.8%19.3% and 21.1% for the sixnine months ended JuneSeptember 30, 2019 and 2018, 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.

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PECO

Results of Operations — PECO
Three Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 Six Months Ended
June 30,		 Favorable
(Unfavorable)
Variance		Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 Favorable
(Unfavorable)
Variance
2019 2018 2019 2018 2019 2018 2019 2018 
Operating revenues$655
 $653
 $2
 $1,554
 $1,518
 $36
$778
 $757
 $21
 $2,333
 $2,275
 $58
Purchased power and fuel expense191
 222
 31
 520
 555
 35
246
 263
 17
 767
 818
 51
Revenues net of purchased power and fuel expense464
 431
 33
 1,034
 963
 71
532
 494
 38
 1,566
 1,457
 109
Other operating expenses                      
Operating and maintenance199
 191
 (8) 424
 466
 42
219
 219
 —
 643
 686
 43
Depreciation and amortization83
 74
 (9) 164
 149
 (15)83
 75
 (8) 247
 224
 (23)
Taxes other than income37
 39
 2
 79
 79
 —
47
 46
 (1) 126
 125
 (1)
Total other operating expenses319
 304
 (15) 667
 694
 27
349
 340
 (9) 1,016
 1,035
 19
Gain on sales of assets—
 —
 —
 —
 1
 (1)
Operating income145
 127
 18
 367
 269
 98
183
 154
 29
 550
 423
 127
Other income and (deductions)                      
Interest expense, net(33) (32) (1) (67) (64) (3)(33) (32) (1) (100) (96) (4)
Other, net3
 —
 3
 7
 2
 5
4
 2
 2
 11
 4
 7
Total other income and (deductions)(30) (32) 2
 (60) (62) 2
(29) (30) 1
 (89) (92) 3
Income before income taxes115
 95
 20
 307
 207
 100
154
 124
 30
 461
 331
 130
Income taxes13
 (1) (14) 37
 (3) (40)14
 (2) (16) 51
 (5) (56)
Net income$102
 $96
 $6
 $270
 $210
 $60
$140
 $126
 $14
 $410
 $336
 $74
Three Months Ended JuneSeptember 30, 2019 Compared to Three Months Ended JuneSeptember 30, 2018. Net income increased by $6$14 million primarily due to higher electric distribution rates that became effective January 2019 and higher natural gas distribution rates, partially offset by unfavorable weather conditions.conditions and volume.
SixNine Months Ended JuneSeptember 30, 2019 Compared to SixNine Months Ended JuneSeptember 30, 2018. Net income increased by $60$74 million primarily due to higher electric distribution rates that became effective January 2019, higher natural gas distribution rates and lower storm costs, partially offset by unfavorable weather conditions.conditions and volume.
Revenues Net of Purchased Power and Fuel Expense
There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power and fuel expense such as commodity and REC procurement costs and participation in customer choice programs. PECO recovers electricity, natural gas and REC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity and natural gas.

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PECO

The changes in RNF consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas TotalElectric Gas Total Electric Gas Total
Weather$(5) $(7) $(12) $(5) $(5) $(10)$(3) $(1) $(4) $(9) $(6) $(15)
Volume(6) 3
 (3) (4) 5
 1
(7) 1
 (6) (11) 6
 (5)
Pricing35
 5
 40
 49
 14
 63
42
 —
 42
 91
 14
 105
Regulatory required programs10
 1
 11
 21
 5
 26
13
 1
 14
 35
 6
 41
Transmission(11) —
 (11) (17) —
 (17)
Other(3) —
 (3) (9) —
 (9)3
 —
 3
 —
 —
 —
Total increase$31
 $2
 $33
 $52
 $19
 $71
$37
 $1
 $38
 $89
 $20
 $109
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 sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018, RNF related to weather decreased due to unfavorable 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 sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 and normal weather consisted of the following:
Heating and Cooling Degree-Days  Normal % Change  Normal % Change
Three Months Ended June 30,2019 2018From 2018 2019 vs. Normal
Three Months Ended September 30,2019 2018 Normal From 2018 2019 vs. Normal
Heating Degree-Days270
 482
 435
 (44.0)% (37.9)%2
 13
(84.6)% (92.6)%
Cooling Degree-Days425
 382
 384
 11.3 % 10.7 %1,143
 1,124
 1,001
 1.7 % 14.2 %
                  
Six Months Ended June 30,         
Nine Months Ended September 30,         
Heating Degree-Days2,702
 2,879
 2,863
 (6.1)% (5.6)%2,704
 2,892
 2,890
 (6.5)% (6.4)%
Cooling Degree-Days427
 382
 385
 11.8 % 10.9 %1,570
 1,506
 1,386
 4.2 % 13.3 %
Volume. Electric volume, exclusive of the effects of weather, for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018, decreased due to the impact of energy efficiency initiatives on customer usages for residential, commercial and industrial electric classes, partially offset by the impact of customer growth.  Natural gas volume for the three and nine months ended June 30, 2019, compared to the same period in 2018, decreased due to lower customer usages for residential, commercial and industrial classes, partially offset by customer growth. Natural gas volume for the six months ended JuneSeptember 30, 2019, compared to the same period in 2018, increased due to customer and economic growth.

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Electric Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		 % Change 
Weather -
Normal
% Change(b)
 Six Months Ended June 30, % Change 
Weather -
Normal
% Change(b)
Three Months Ended
September 30,		 % Change 
Weather -
Normal
% Change(b)
 Nine Months Ended September 30, % Change 
Weather -
Normal
% Change(b)
2019 2018 2019 2018 2019 2018 2019 2018 
Residential2,821
 2,946
 (4.2)% (1.1)% 6,462
 6,574
 (1.7)% (0.3)%4,106
 4,166
 (1.4)% (0.8)% 10,568
 10,741
 (1.6)% (0.5)%
Small commercial & industrial1,823
 1,930
 (5.5)% (5.2)% 3,889
 3,958
 (1.7)% (1.6)%2,203
 2,315
 (4.8)% (2.0)% 6,093
 6,273
 (2.9)% (1.7)%
Large commercial & industrial3,769
 3,811
 (1.1)% (1.3)% 7,340
 7,514
 (2.3)% (2.4)%4,109
 4,378
 (6.1)% (6.3)% 11,449
 11,892
 (3.7)% (3.9)%
Public authorities & electric railroads182
 182
 — % (1.7)% 377
 379
 (0.5)% (1.3)%183
 189
 (3.2)% (3.3)% 560
 568
 (1.4)% (2.0)%
Total electric retail deliveries(a)
8,595
 8,869
 (3.1)% (2.1)% 18,068
 18,425
 (1.9)% (1.5)%10,601
 11,048
 (4.0)% (3.3)% 28,670
 29,474
 (2.7)% (2.1)%
As of June 30,As of September 30,
Number of Electric Customers2019 20182019 2018
Residential1,486,973
 1,474,901
1,489,046
 1,476,914
Small commercial & industrial153,387
 152,152
153,400
 152,253
Large commercial & industrial3,105
 3,114
3,104
 3,124
Public authorities & electric railroads9,733
 9,544
9,775
 9,561
Total1,653,198
 1,639,711
1,655,325
 1,641,852
_________
(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.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Natural Gas Deliveries to Customers (in mmcf)Three Months Ended
June 30,		 % Change 
Weather -
Normal
% Change(b)
 Six Months Ended
June 30,		 % Change 
Weather -
Normal
% Change(b)
Three Months Ended
September 30,		 % Change 
Weather -
Normal
% Change(b)
 Nine Months Ended
September 30,		 % Change 
Weather -
Normal
% Change(b)
2019 2018 2019 2018 2019 2018 2019 2018 
Residential3,351
 5,889
 (43.1)% (2.1)% 24,569
 26,463
 (7.2)% 0.6 %2,109
 2,099
 0.5 % 7.9 % 26,678
 28,562
 (6.6)% 1.1%
Small commercial & industrial4,040
 3,598
 12.3 % (1.5)% 14,684
 14,016
 4.8 % (0.4)%1,901
 1,776
 7.0 % 15.1 % 16,585
 15,792
 5.0 % 1.2%
Large commercial & industrial17
 6
 183.3 % 22.5 % 36
 52
 (30.8)% 3.1 %10
 6
 66.7 % 12.4 % 46
 58
 (20.7)% 6.0%
Transportation5,719
 5,981
 (4.4)% — % 13,692
 13,549
 1.1 % 3.2 %5,395
 5,693
 (5.2)% (3.4)% 19,087
 19,242
 (0.8)% 1.3%
Total natural gas retail deliveries(a)
13,127
 15,474
 (15.2)% (0.9)% 52,981
 54,080
 (2.0)% 1.0 %9,415
 9,574
 (1.7)% 2.5 % 62,396
 63,654
 (2.0)% 1.2%
As of June 30,As of September 30,
Number of Natural Gas Customers2019 20182019 2018
Residential483,657
 478,954
484,676
 479,732
Small commercial & industrial43,953
 43,748
43,869
 43,638
Large commercial & industrial2
 1
2
 1
Transportation737
 767
735
 761
Total528,349
 523,470
529,282
 524,132
_________
(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.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 increased primarily due to an increase in electric distribution rates charged to customers.  The increase in electric distribution rates was effective January 1, 2019 in accordance with the 2018 PAPUC approved electric distribution rate case settlement. Additionally, the increase represents revenue from higher natural gas distribution rates. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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PECO

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as smart meter, energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Income taxes.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the three and nine months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to lower income taxes and operating and maintenance expenses. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes rental revenue, revenue related to late payment charges and mutual assistance revenues and wholesale transmission revenue.revenues.
See Note 18— Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Baseline      
Labor, other benefits, contracting and materials$—
 $9
$(5) $4
Storm-related costs(a)
7
 (49)8
 (42)
Pension and non-pension postretirement benefits expense(1) (3)(1) (4)
BSC costs(1) 2
2
 4
Other2
 (1)(5) (6)
7
 (42)(1) (44)
Regulatory Required Programs      
Energy efficiency1
 —
1
 1
Total increase (decrease)$8
 $(42)
Total decrease$—
 $(43)
__________
(a)Reflects decreased storm costs due to the March 2018 winter storms.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended June 30, 2019 Six Months Ended
June 30, 2019		Three Months Ended September 30, 2019 Nine Months Ended
September 30, 2019
Increase (Decrease) IncreaseIncrease Increase
Depreciation and amortization(a)
$9
 $14
$7
 $21
Regulatory asset amortization1
 11
 2
Other(1) —
Total increase$9
 $15
$8
 $23
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective Income Tax Rates were 11.3%9.1% and (1.1)(1.6)% for the three months ended JuneSeptember 30, 2019 and 2018, respectively, and 12.1%11.1% and (1.4)(1.5)% for the sixnine months ended JuneSeptember 30, 2019 and 2018, 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.

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BGE


Results of Operations — BGE
 Three Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 Six Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 2019 2018  2019 2018 
Operating revenues$649
 $662
 $(13) $1,625
 $1,639
 $(14)
Purchased power and fuel expense208
 229
 21
 570
 609
 39
Revenues net of purchased power and fuel expense441
 433
 8
 1,055
 1,030
 25
Other operating expenses           
Operating and maintenance182
 176
 (6) 372
 397
 25
Depreciation and amortization117
 114
 (3) 252
 248
 (4)
Taxes other than income62
 59
 (3) 131
 124
 (7)
Total other operating expenses361
 349
 (12) 755
 769
 14
Gain on sales of assets—
 1
 (1) —
 1
 (1)
Operating income80
 85
 (5) 300
 262
 38
Other income and (deductions)           
Interest expense, net(29) (25) (4) (58) (51) (7)
Other, net5
 4
 1
 11
 9
 2
Total other income and (deductions)(24) (21) (3) (47) (42) (5)
Income before income taxes56
 64
 (8) 253
 220
 33
Income taxes11
 13
 2
 47
 41
 (6)
Net income$45
 $51
 $(6) $206
 $179
 $27

 Three Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
 2019 2018  2019 2018 
Operating revenues$703
 $731
 $(28) $2,327
 $2,369
 $(42)
Purchased power and fuel expense235
 272
 37
 804
 881
 77
Revenues net of purchased power and fuel expense468
 459
 9
 1,523
 1,488
 35
Other operating expenses           
Operating and maintenance196
 182
 (14) 569
 578
 9
Depreciation and amortization116
 110
 (6) 368
 358
 (10)
Taxes other than income65
 64
 (1) 195
 188
 (7)
Total other operating expenses377
 356
 (21) 1,132
 1,124
 (8)
Gain on sales of assets—
 —
 —
 —
 1
 (1)
Operating income91
 103
 (12) 391
 365
 26
Other income and (deductions)           
Interest expense, net(31) (27) (4) (89) (78) (11)
Other, net7
 5
 2
 18
 14
 4
Total other income and (deductions)(24) (22) (2) (71) (64) (7)
Income before income taxes67
 81
 (14) 320
 301
 19
Income taxes12
 18
 6
 59
 59
 —
Net income$55
 $63
 $(8) $261
 $242
 $19
Three Months Ended JuneSeptember 30, 2019 Compared to Three Months Ended JuneSeptember 30, 2018. Net income decreased by $6$8 million primarily due to an increase in various expenses, including interest, partially offset by higher natural gas distribution rates that became effective January 2019.
SixNine Months Ended JuneSeptember 30, 2019 Compared to SixNine Months Ended JuneSeptember 30, 2018. Net income increased by $27$19 million primarily due to higher natural gas distribution rates that became effective January 2019 and lower storm costs, partially offset by higher interest expense.an increase in various expenses, including interest.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and participation in customer choice programs. BGE recovers electricity, natural gas and procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity and natural gas from electric generation and natural gas competitive suppliers. Customer choice programs do not impact the volume of deliveries or RNF but impact Operating revenues related to supplied electricity and natural gas.

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BGE


The changes in RNF consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas TotalElectric Gas Total Electric Gas Total
Distribution$1
 $11
 $12
 $6
 $42
 $48
$2
 $7
 $9
 $7
 $48
 $55
Regulatory required programs(2) (2) (4) (4) (5) (9)(1) 1
 —
 (6) (3) (9)
Transmission3
 —
 3
 (2) —
 (2)2
 —
 2
 (3) —
 (3)
Other, net(1) (2) (3) (8) (4) (12)—
 (2) (2) (4) (4) (8)
Total increase (decrease)$1
 $7
 $8
 $(8) $33
 $25
$3
 $6
 $9
 $(6) $41
 $35
Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
As of June 30,As of September 30,
Number of Electric Customers2019 20182019 2018
Residential1,171,815
 1,163,789
1,174,188
 1,165,012
Small commercial & industrial113,982
 113,745
114,301
 114,082
Large commercial & industrial12,275
 12,183
12,296
 12,218
Public authorities & electric railroads264
 268
264
 263
Total1,298,336
 1,289,985
1,301,049
 1,291,575
As of June 30,As of September 30,
Number of Natural Gas Customers2019 20182019 2018
Residential634,939
 630,714
636,030
 631,589
Small commercial & industrial38,164
 38,274
38,129
 38,175
Large commercial & industrial5,991
 5,900
6,005
 5,920
Total679,094
 674,888
680,164
 675,684
Distribution Revenue increased for the three and sixnine months ended JuneSeptember 30, 2019, compared to the same period in 2018, primarily due to the impact of higher natural gas distribution rates that became effective in January 2019. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue remained relatively consistent for the three and sixnine months ended JuneSeptember 30, 2019, compared to the same period in 2018. See Operating and maintenance expense below and Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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BGE


Other revenue includes revenue related to administrative charges, mutual assistance, revenues,administrative charges, off-system sales, and late payment charges.
See Note 18 — Segment Information of the Combined Notes to the Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Baseline      
Storm-related costs(a)
$6
 $(24)$(3) $(26)
Labor, other benefits, contracting and materials4
 3
12
 16
Pension and non-pension postretirement benefits expense—
 1
—
 1
Uncollectible accounts expense(1) (1)(1) (1)
BSC costs(1) 1
1
 2
Other(1) (4)5
 —
7
 (24)14
 (8)
Regulatory Required Programs      
Other(1) (1)—
 (1)
Total decrease$6
 $(25)
Total increase (decrease)$14
 $(9)
__________
(a)For the sixnine months ended JuneSeptember 30, 2019, reflects decreased storm costs due to the March 2018 winter storms.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Depreciation and amortization(a)
$6
 $11
$4
 $15
Regulatory asset amortization—
 1
2
 3
Regulatory required programs(3) (8)—
 (8)
Total increase$3
 $4
$6
 $10
_________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net for the three and nine months ended September 30, 2019 compared to the same period in 2018, increased due to the issuance of debt in September 2018.
Effective income tax rates were 19.6%17.9% and 20.3%22.2% for the three months ended JuneSeptember 30, 2019 and 2018, respectively, and 18.6% both18.4% and 19.6% for the sixnine months ended JuneSeptember 30, 2019 and 2018.2018, 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.

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PHI

Results of Operations — PHI
PHI’s results of operations include the results of its three reportable segments, Pepco, DPL and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. See the results of operations for Pepco, DPL and ACE for additional information.
Three Months Ended
June 30,		 Favorable (Unfavorable) Variance Six Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
Three Months Ended
September 30,		 Favorable (Unfavorable) Variance Nine Months Ended
September 30,		 
Favorable
(Unfavorable)
Variance
2019 2018 2019 2018 2019 2018 2019 2018 
PHI$106
 $84
 $22
 $223
 $149
 $74
$189
 $187
 $2
 $412
 $336
 $76
Pepco64
 54
 10
 119
 85
 34
98
 89
 9
 217
 174
 43
DPL30
 26
 4
 83
 57
 26
33
 33
 —
 116
 90
 26
ACE14
 8
 6
 24
 15
 9
63
 61
 2
 87
 76
 11
Other(a)
(2) (4) 2
 (3) (8) 5
(5) 4
 (9) (8) (4) (4)
_________
(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities and other financing and investing activities.
Three Months Ended JuneSeptember 30, 2019 Compared to Three Months Ended JuneSeptember 30, 2018. Net Income remained relatively consistent with the same period in 2018 primarily due to higher electric and natural gas distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, partially offset by an increase in environmental liabilities and various expenses.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018. Net Incomeincreased by $22$76 million primarily due to higher electric and natural gas distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, and lower contracting costs.
Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Net Income increased by $74 million primarily due to higher electric and natural gas distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, lower contracting costs, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, lower uncollectible accounts expense, and lower write-offs of construction work in progress.progress, partially offset by an increase in environmental liabilities and various expenses.


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Pepco


Results of Operations — Pepco
Three Months Ended June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) VarianceThree Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2019 2018 2019 2018 2019 2018 2019 2018 
Operating revenues$531
 $523
 $8
 $1,106
 $1,080
 $26
$642
 $628
 $14
 $1,748
 $1,708
 $40
Purchased power expense144
 140
 (4) 331
 322
 (9)181
 177
 (4) 513
 497
 (16)
Revenues net of purchased power expense387
 383
 4
 775
 758
 17
461
 451
 10
 1,235
 1,211
 24
Other operating expenses                      
Operating and maintenance111
 116
 5
 230
 246
 16
135
 136
 1
 364
 383
 19
Depreciation and amortization93
 92
 (1) 186
 188
 2
95
 99
 4
 281
 286
 5
Taxes other than income90
 90
 —
 182
 183
 1
104
 104
 —
 286
 288
 2
Total other operating expenses294
 298
 4
 598
 617
 19
334
 339
 5
 931
 957
 26
Operating income93
 85
 8
 177
 141
 36
127
 112
 15
 304
 254
 50
Other income and (deductions)    
     
    
     
Interest expense, net(34) (32) (2) (68) (63) (5)(33) (32) (1) (100) (96) (4)
Other, net7
 8
 (1) 14
 16
 (2)9
 7
 2
 22
 23
 (1)
Total other income and (deductions)(27) (24) (3) (54) (47) (7)(24) (25) 1
 (78) (73) (5)
Income before income taxes66
 61
 5
 123
 94
 29
103
 87
 16
 226
 181
 45
Income taxes2
 7
 5
 4
 9
 5
5
 (2) (7) 9
 7
 (2)
Net income$64
 $54
 $10
 $119
 $85
 $34
$98
 $89
 $9
 $217
 $174
 $43
Three Months Ended JuneSeptember 30, 2019 Compared to Three Months Ended JuneSeptember 30, 2018. Net income increased by $10$9 million primarily due to higher electric distribution rates in Maryland that became effective June 2018 (not reflecting the impact of TCJA),August 2019, higher electric distribution rates in the District of Columbia that became effective August 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, and lower contracting costs.the absence of the charge associated with a remeasurement of the Buzzard Point ARO, partially offset by an increase in environmental liabilities.
SixNine Months Ended JuneSeptember 30, 2019 Compared to SixNine Months Ended JuneSeptember 30, 2018. Net income increased by $34$43 million primarily due to higher electric distribution rates in Maryland that became effective August 2019 and June 2018 (not reflecting the impact of TCJA), higher electric distribution rates in the District of Columbia that became effective August 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, lower contracting costs, and lower uncollectible accounts expense.expense, partially offset by an increase in environmental liabilities.
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity and REC procurement costs and participation in customer choice programs. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity.

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Pepco


The changes in RNF consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Volume$4
 $8
$4
 $11
Distribution4
 10
9
 19
Regulatory required programs(8) (18)(8) (26)
Transmission7
 20
2
 22
Other(3) (3)3
 (2)
Total increase$4
 $17
$10
 $24
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
Volume, exclusive of the effects of weather, increased for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018, primarily due to the impact of residential customer growth.
As of June 30,As of September 30,
Number of Electric Customers2019 20182019 2018
Residential811,985
 798,741
814,412
 802,607
Small commercial & industrial54,194
 53,460
54,130
 53,700
Large commercial & industrial22,155
 21,846
22,240
 21,927
Public authorities & electric railroads155
 147
158
 147
Total888,489
 874,194
890,940
 878,381
Distribution Revenues increased for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates (not reflecting the impact of TCJA) in Maryland that became effective in August 2019 and June 2018 and(not reflecting the impact of TCJA), higher electric distribution rates (not reflecting the impact of TCJA) in the District of Columbia that became effective in August 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 6 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG and SOS administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.
Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenues increased for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 primarily due to rate increases and an increase in the highest daily peak load.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of other taxes.

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Pepco


See Note 18 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Baseline      
Labor, other benefits, contracting and materials$(5) $(11)$(2) $(14)
Pension and non-pension postretirement benefits expense2
 3
2
 5
Uncollectible accounts expense(2) (5)1
 (4)
Storm-related costs—
 (3)2
 (1)
BSC and PHISCO costs(4) (7)(2) (9)
Other6
 10
(2) 7
(3) (13)(1) (16)
      
Regulatory required programs(2) (3)—
 (3)
Total decrease$(5) $(16)$(1) $(19)
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Depreciation and amortization(a)
$6
 $11
$6
 $17
Regulatory asset amortization(b)
1
 2
Regulatory required programs(6) (15)(10) (22)
Total increase (decrease)$1
 $(2)
Total decrease$(4) $(5)
_________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b)Regulatory asset amortization increased primarily due to additional regulatory assets related to rate case activity.

Interest expense, net for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.
Effective income tax rates were 3.0%4.9% and 11.5%(2.3)% for the three months ended JuneSeptember 30, 2019 and 2018, respectively, and 3.3%4.0% and 9.6%3.9% for the sixnine months ended JuneSeptember 30, 2019 and 2018, respectively. The decreaseincrease is primarily due to the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. 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.

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DPL


Results of Operations — DPL
Three Months Ended June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) VarianceThree Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2019 2018 2019 2018 2019 2018 2019 2018 
Operating revenues$287
 $289
 $(2) $667
 $673
 $(6)$319
 $328
 $(9) $987
 $1,001
 $(14)
Purchased power and fuel expense107
 114
 7
 271
 291
 20
127
 133
 6
 399
 425
 26
Revenues net of purchased power and fuel expense180
 175
 5
 396
 382
 14
192
 195
 (3) 588
 576
 12
Other operating expenses

 

   

 

  

 

   

 

  
Operating and maintenance77
 77
 —
 160
 175
 15
80
 82
 2
 240
 256
 16
Depreciation and amortization45
 43
 (2) 91
 88
 (3)46
 47
 1
 138
 135
 (3)
Taxes other than income14
 13
 (1) 28
 28
 —
15
 15
 —
 43
 43
 —
Total other operating expenses136
 133
 (3) 279
 291
 12
141
 144
 3
 421
 434
 13
Operating income44
 42
 2
 117
 91
 26
51
 51
 —
 167
 142
 25
Other income and (deductions)

 

 

 

 

 



 

 

 

 

 

Interest expense, net(15) (14) (1) (30) (27) (3)(15) (15) —
 (45) (42) (3)
Other, net5
 3
 2
 7
 5
 2
2
 2
 —
 10
 7
 3
Total other income and (deductions)(10) (11) 1
 (23) (22) (1)(13) (13) —
 (35) (35) —
Income before income taxes34

31
 3
 94

69
 25
38

38
 —
 132

107
 25
Income taxes4
 5
 1
 11
 12
 1
5
 5
 —
 16
 17
 1
Net income$30
 $26
 $4
 $83
 $57
 $26
$33
 $33
 $—
 $116
 $90
 $26
Three Months Ended JuneSeptember 30, 2019 Compared to Three Months Ended JuneSeptember 30, 2018. Net income remained consistent with the same period in 2018.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018. Net income increased by $4$26 million primarily due to higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, higher electric distribution rates in Maryland and Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), higher natural gas distribution rates in Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), and higher transmission revenues due to an increase in the transmission rates and the highest daily peak load.
Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Net income increased by $26 million primarily due to higher electric distribution rates in Maryland and Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), higher natural gas distribution rates in Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, and lower write-offs of construction work in progress.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity and REC procurement costs and participation in customer choice programs. DPL recovers electricity and REC procurement costs from customers with a slight mark-up and natural gas costs from customers without mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity.

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DPL


The changes in RNF consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas TotalElectric Gas Total Electric Gas Total
Weather$—
 $(3) $(3) $—
 $(2) $(2)$—
 $—
 $—
 $—
 $(2) $(2)
Volume1
 —
 1
 —
 2
 2
—
 (1) (1) —
 1
 1
Distribution(2) 2
 —
 2
 —
 2
1
 —
 1
 3
 —
 3
Regulatory required programs(2) —
 (2) (4) (1) (5)(2) 1
 (1) (6) 1
 (5)
Transmission9
 —
 9
 17
 —
 17
1
 —
 1
 18
 —
 18
Other(3) —
 (3) (3) —
 (3)
Total increase (decrease)$6
 $(1) $5
 $15
 $(1) $14
$(3) $—
 $(3) $12
 $—
 $12
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018, RNF related to weather decreased primarily due to unfavorable weather conditions in DPL's Delaware service territory.remained relatively consistent.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the three and sixnine months ended JuneSeptember 30, 2019 compared to same period in 2018 and normal weather consisted of the following:
Delaware Electric Service Territory    % Change    % Change
Three Months Ended June 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Three Months Ended September 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days300
 481
 476
 (37.6)% (37.0)%6
 11
 33
 (45.5)% (81.8)%
Cooling Degree-Days386
 349
 327
 10.6 % 18.0 %1,043
 1,027
 871
 1.6 % 19.7 %
                  
    % Change    % Change
Six Months Ended June 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Nine Months Ended September 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days2,822
 2,985
 2,984
 (5.5)% (5.4)%2,828
 2,995
 3,017
 (5.6)% (6.3)%
Cooling Degree-Days386
 349
 328
 10.6 % 17.7 %1,429
 1,376
 1,198
 3.9 % 19.3 %
Delaware Natural Gas Service Territory    % Change    % Change
Three Months Ended June 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Three Months Ended September 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days300
 481
 495
 (37.6)% (39.4)%6
 11
 41
 (45.5)% (85.4)%
                  
    % Change    % Change
Six Months Ended June 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Nine Months Ended September 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days2,822
 2,985
 2,990
 (5.5)% (5.6)%2,828
 2,995
 3,031
 (5.6)% (6.7)%

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DPL


Volume, exclusive of the effects of weather, increasedremained relatively consistent for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 primarily due to residential customer growth.2018.
Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended
June 30,		 % Change 
Weather - Normal
% Change(b)
 Six Months Ended
June 30,		 % Change 
Weather - Normal
% Change(b)
Three Months Ended
September 30,		 % Change 
Weather - Normal
% Change(b)
 Nine Months Ended
September 30,		 % Change 
Weather - Normal
% Change(b)
2019 2018 2019 2018 2019 2018 2019 2018 
Residential652
 671
 (2.8)% (0.6)% 1,503
 1,541
 (2.5)% (1.1)%947
 945
 0.2 % 0.3 % 2,450
 2,485
 (1.4)% (0.6)%
Small commercial & industrial306
 321
 (4.7)% (4.3)% 626
 651
 (3.8)% (3.5)%387
 376
 2.9 % 2.5 % 1,013
 1,027
 (1.4)% (1.3)%
Large commercial & industrial866
 928
 (6.7)% (6.7)% 1,676
 1,757
 (4.6)% (4.6)%924
 973
 (5.0)% (5.2)% 2,600
 2,730
 (4.8)% (4.8)%
Public authorities & electric railroads9
 8
 12.5 % 12.8 % 17
 17
 — % 2.2 %8
 8
 — % (1.1)% 25
 25
 — % 1.1 %
Total electric retail deliveries(a)
1,833
 1,928
 (4.9)% (4.1)% 3,822
 3,966
 (3.6)% (3.0)%2,266
 2,302
 (1.6)% (1.7)% 6,088
 6,267
 (2.9)% (2.6)%
As of June 30,As of September 30,
Number of Total Electric Customers (Maryland and Delaware)2019 20182019 2018
Residential465,423
 461,596
466,972
 463,017
Small commercial & industrial61,552
 61,189
61,657
 61,277
Large commercial & industrial1,398
 1,362
1,418
 1,400
Public authorities & electric railroads619
 624
616
 622
Total528,992
 524,771
530,663
 526,316
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Natural Gas Retail Deliveries to Delaware Customers (in mmcf)Three Months Ended
June 30,		 % Change 
Weather - Normal
% Change(b)
 Six Months Ended
June 30,		 % Change 
Weather - Normal
% Change(b)
Three Months Ended
September 30,		 % Change 
Weather - Normal
% Change(b)
 Nine Months Ended
September 30,		 % Change 
Weather - Normal
% Change(b)
2019 2018 2019 2018 2019 2018 2019 2018 
Residential741
 957
 (22.6)% 9.6 % 5,348
 5,442
 (1.7)% 3.2 %403
 360
 11.9 % 11.8 % 5,751
 5,801
 (0.9)% 3.8 %
Small commercial & industrial566
 644
 (12.1)% 8.6 % 2,586
 2,521
 2.6 % 7.1 %386
 309
 24.9 % 22.9 % 2,972
 2,831
 5.0 % 8.9 %
Large commercial & industrial442
 466
 (5.2)% (5.2)% 965
 984
 (1.9)% (1.8)%407
 454
 (10.4)% (10.4)% 1,372
 1,438
 (4.6)% (4.5)%
Transportation1,475
 1,420
 3.9 % 8.8 % 3,693
 3,633
 1.7 % 3.3 %1,212
 1,260
 (3.8)% (3.5)% 4,905
 4,893
 0.2 % 1.6 %
Total natural gas deliveries(a)
3,224
 3,487
 (7.5)% 7.1 % 12,592
 12,580
 0.1 % 3.6 %2,408
 2,383
 1.0 % 1.4 % 15,000
 14,963
 0.2 % 3.3 %
As of June 30,As of September 30,
Number of Delaware Natural Gas Customers2019 20182019 2018
Residential124,325
 122,754
124,944
 123,145
Small commercial & industrial9,907
 9,810
9,885
 9,798
Large commercial & industrial18
 18
18
 19
Transportation158
 154
158
 154
Total134,408
 132,736
135,005
 133,116
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

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DPL


Distribution Revenue increased for the sixthree and nine months ended JuneSeptember 30, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates (not reflecting the impact of TCJA) in Maryland and Delaware that became effective throughout 2018 and higher natural gas distribution rates (not reflecting the impact of TCJA) in Delaware that became effective throughout 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS administrative costs and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.
Transmission Revenues. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar years. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 due to rate increases and an increase in the highest daily peak load.
See Note 18 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Baseline      
Labor, other benefits, contracting and materials$(1) $1
$(2) $1
Pension and non-pension postretirement benefits expense1
 1
1
 3
Uncollectible accounts expense3
 (1)(3) (4)
Storm-related costs1
 (3)2
 (1)
BSC and PHISCO costs(3) (5)(1) (6)
Write-offs of construction work in progress—
 (7)—
 (7)
Other(2) —
1
 (1)
(1) (14)(2) (15)
      
Regulatory required programs1
 (1)—
 (1)
Total decrease$—
 $(15)$(2) $(16)
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Depreciation and amortization(a)
$4
 $7
$4
 $11
Regulatory asset amortization(1) (1)
Regulatory required programs(2) (4)(4) (7)
Total increase$2
 $3
Total increase (decrease)$(1) $3
_________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

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DPL


Interest expense, net for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.
Effective income tax rates were 11.8%13.2% and 16.1%13.2% for the three months ended JuneSeptember 30, 2019 and 2018, respectively, and 11.7%12.1% and 17.4%15.9% for the sixnine months ended JuneSeptember 30, 2019 and 2018, respectively. The decrease for the nine months ended September 30, 2019 is primarily due to the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. 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.

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ACE


Results of Operations — ACE
Three Months Ended June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) VarianceThree Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2019 2018 2019 2018 2019 2018 2019 2018 
Operating revenues$274
 $265
 $9
 $547
 $575
 $(28)$419
 $406
 $13
 $966
 $981
 $(15)
Purchased power expense131
 128
 (3) 270
 289
 19
210
 198
 (12) 479
 486
 7
Revenues net of purchased power expense143
 137
 6
 277
 286
 (9)209
 208
 1
 487
 495
 (8)
Other operating expenses    
     
    
     
Operating and maintenance74
 75
 1
 155
 165
 10
86
 85
 (1) 241
 250
 9
Depreciation and amortization40
 36
 (4) 71
 69
 (2)43
 38
 (5) 114
 107
 (7)
Taxes other than income1
 1
 —
 2
 3
 1
1
 1
 —
 4
 4
 —
Total other operating expenses115
 112
 (3) 228
 237
 9
130
 124
 (6) 359
 361
 2
Operating income28
 25
 3
 49
 49
 —
79
 84
 (5) 128
 134
 (6)
Other income and (deductions)    
     
    
     
Interest expense, net(15) (16) 1
 (28) (32) 4
(15) (16) 1
 (44) (48) 4
Other, net1
 1
 —
 4
 1
 3
1
 1
 —
 5
 2
 3
Total other income and (deductions)(14)
(15) 1
 (24)
(31) 7
(14)
(15) 1
 (39)
(46) 7
Income before income taxes14

10
 4
 25

18
 7
65

69
 (4) 89

88
 1
Income taxes—
 2
 2
 1
 3
 2
2
 8
 6
 2
 12
 10
Net income$14
 $8
 $6
 $24
 $15
 $9
$63
 $61
 $2
 $87
 $76
 $11
Three Months Ended JuneSeptember 30, 2019 Compared to Three Months Ended JuneSeptember 30, 2018. Net income increased by $6 million primarily due to higher electric distribution rates effective April 2019 and higher transmission revenues due to an increaseremained relatively consistent with the same period in the transmission rates and the highest daily peak load.2018.
SixNine Months Ended JuneSeptember 30, 2019 Compared to SixNine Months Ended JuneSeptember 30, 2018. Net income increased by $9$11 million primarily due to higher electric distribution rates that became effective April 2019 and higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, partially offset by lower average residential usage.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity and REC procurement costs and participation in customer choice programs. ACE recovers electricity and REC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity.

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The changes in RNF consisted of the following:
 Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019
 Increase (Decrease) Increase (Decrease)
Volume$—
 $(6)
Distribution8
 5
Regulatory required programs(5) (16)
Transmission3
 8
Total increase (decrease)$6
 $(9)

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 Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
 Increase (Decrease) Increase (Decrease)
Weather$(4) $(4)
Volume(4) (10)
Distribution16
 21
Regulatory required programs(12) (28)
Transmission7
 15
Other(2) (2)
Total increase (decrease)$1
 $(8)
Weather. The demand for electricity is affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. There was no change in RNFa decrease related to weather for the three and sixnine months ended JuneSeptember 30, 2019 compared to same period in 2018. due to the impact of unfavorable weather conditions in ACE's service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating degree days in ACE’s service territory for the three and sixnine months ended JuneSeptember 30, 2019 compared to same period in 2018 consisted of the following:
Heating and Cooling Degree-Days  Normal % Change  Normal % Change
Three Months Ended June 30,2019 2018 2019 vs. 2018 2019 vs. Normal
Three Months Ended September 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days380
 515
 553
 (26.2)% (31.3)%13
 1
 1,200.0 % (65.8)%
Cooling Degree-Days351
 354
 297
 (0.8)% 18.2 %980
 1,093
 831
 (10.3)% 17.9 %
                  
  Normal % Change  Normal % Change
Six Months Ended June 30,2019 2018 2019 vs. 2018 2019 vs. Normal
Nine Months Ended September 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days2,886
 2,927
 3,042
 (1.4)% (5.1)%2,899
 2,928
 (1.0)% (5.9)%
Cooling Degree-Days351
 354
 297
 (0.8)% 18.2 %1,330
 1,447
 1,129
 (8.1)% 17.8 %
Volume, exclusive of the effects of weather, decreased for the sixthree and nine months ended JuneSeptember 30, 2019 compared to the same period in 2018, primarily due to lower average residential usage.
Electric Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		 % Change 
Weather - Normal % Change(b)
 Six Months Ended
June 30,		 % Change 
Weather - Normal
% Change(b)
Three Months Ended
September 30,		 % Change 
Weather - Normal % Change(b)
 Nine Months Ended
September 30,		 % Change 
Weather - Normal
% Change(b)
2019 2018 2019 2018 2019 2018 2019 2018 
Residential804
 825
 (2.5)% (1.6)% 1,713
 1,815
 (5.6)% (5.7)%1,470
 1,548
 (5.0)% (1.6)% 3,182
 3,363
 (5.4)% (3.9)%
Small commercial & industrial314
 309
 1.6 % 2.2 % 624
 623
 0.2 % 0.4 %431
 442
 (2.5)% (0.5)% 1,055
 1,066
 (1.0)% 0.1 %
Large commercial & industrial872
 872
 — % 0.1 % 1,662
 1,696
 (2.0)% (2.0)%938
 1,030
 (8.9)% (7.9)% 2,600
 2,725
 (4.6)% (4.2)%
Public authorities & electric railroads11
 11
 — % (1.2)% 24
 26
 (7.7)% (6.6)%10
 10
 — % (3.9)% 34
 36
 (5.6)% (5.9)%
Total electric retail deliveries(a)
2,001
 2,017
 (0.8)% (0.3)% 4,023
 4,160
 (3.3)% (3.2)%2,849
 3,030
 (6.0)% (3.7)% 6,871
 7,190
 (4.4)% (3.4)%

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As of June 30,As of September 30,
Number of Electric Customers2019 20182019 2018
Residential492,940
 489,050
493,720
 489,961
Small commercial & industrial61,416
 61,134
61,376
 61,141
Large commercial & industrial3,464
 3,590
3,418
 3,569
Public authorities & electric railroads672
 654
676
 656
Total558,492
 554,428
559,190
 555,327
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Distribution Revenue increased for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates charged to customers that became effective in April 2019, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon

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the enactment of TCJA as the result of regulatory settlements. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds and BGS administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.
Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 primarily due to rate increases and an increase in the highest daily peak load.
See Note 18 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Baseline      
Labor, other benefits, contracting and materials$—
 $(4)$2
 $(4)
Uncollectible accounts expense(a)
4
 (2)(3) (9)
Storm-related costs2
 (1)1
 1
BSC and PHISCO costs(2) (3)(1) (4)
Other(5) —
3
 (4)
Total decrease$(1) $(10)
2
 (20)
   
Regulatory required programs(1) 11
Total Increase (Decrease)$1
 $(9)
_________
(a)ACE is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues.

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The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2019		 Six Months Ended
June 30, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease) Increase (Decrease)
Depreciation and amortization(a)
$7
 $10
$8
 $19
Regulatory asset amortization(b)
3
 3
3
 5
Regulatory required programs(6) (11)(6) (17)
Total increase$4
 $2
$5
 $7
_________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b)Regulatory asset amortization increased primarily due to additional regulatory assets related to rate case activity.
Interest expense, net for the three and sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 decreased primarily due to lower outstanding debt.
Other, net for the sixnine months ended JuneSeptember 30, 2019 compared to the same period in 2018 increased primarily due to higher income from AFUDC equity.

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Effective income tax rates were 0.0%3.1% and 20.0%11.6% for the three months ended JuneSeptember 30, 2019 and 2018, respectively and 4.0%2.2% and 16.7%13.6% for the sixnine months ended JuneSeptember 30, 2019 and 2018, respectively. The decrease is primarily due to the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. 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.

Liquidity and Capital Resources
All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to unsecured revolving credit facilities with aggregate bank commitments of $9 billion. In addition, Generation has $645 million in bilateral facilities with banks which have various expirations between October 2019 and April 2021 and $159 million in credit facilities for project finance. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
NRC Minimum Funding Requirements (Exelon and Generation)
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are 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 of the Combined Notes to Consolidated Financial Statements for additional information.
If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value. A shortfall could require that Generation address the shortfall by, among other things, obtaining a parental guarantee for Generation’s share of the funding assurance. However, the amount of any guarantees or other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. Within two years after shutting down a plant, Generation must submit a PSDAR to the NRC that includes the planned option for decommissioning the site. On April 5, 2019, Generation filed with the NRC the TMI PSDAR which details the selection of the SAFSTOR option for decommissioning TMI Unit 1. As of June 30, 2019, under the SAFSTOR approach, sufficient funds would be available to satisfy Generation's radiological decommissioning obligations for TMI Unit 1. See Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.
Upon issuance of any required financial guarantees, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, the NRC must approve an exemption in order for the plant’s owner(s) to utilize the NDT fund to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by the owner(s) without reimbursement from or access to the NDT

funds. While theThe ultimate costs for spent fuel management may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the DOE reimbursement agreements, ifagreements.


As of September 30, 2019, Exelon would not be required to post a parental guarantee for TMI does not obtain an exemption,Unit 1 under the SAFSTOR scenario which is the planned decommissioning option as described in the TMI Unit 1 PSDAR filed by Generation estimates it could incur spent fuel management and site restoration costs overwith the next ten years of up to $95 million net of taxes under SAFSTOR.NRC on April 5, 2019. On April 12,October 16, 2019, Generation submitted anthe NRC granted Generation's exemption request to use the NRC to use TMI Unit 1 NDT funds for spent fuel management activities.costs. An additional exemption request would be required to allow the funds to be spent on site restoration costs, which are not expected to be incurred in the near term.
Project Financing (Exelon and Generation)
Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities. See Note 13 -11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. Refer to Note 13 — Debt and Credit Agreements of the Exelon 2018 Form 10-K for additional information on credit facilities.
Pension Funding Strategy (All Registrants)
Management considers various factors when making qualified 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). Beginning in 2020, Exelon will implement a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $500 million beginning in 2020. This funding strategy does not change Exelon’s expected 2019 qualified pension contributions of approximately $300 million.
Cash Flows from Operating Activities (All Registrants)
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, and their ability to achieve operating cost reductions.
See Notes 4 — Regulatory Matters and 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2018 Form 10-K for additional information of regulatory and legal proceedings and proposed legislation.
The following table provides a summary of the change in cash provided by (used in)flows from operating activities for the sixnine months ended JuneSeptember 30, 2019 and 2018 by Registrant:

Change - Cash Provided by (Used in)Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Increase (Decrease) in cash flows from operating activitiesExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Net income$281
 $172
 $15
 $60
 $27
 $74
 $34
 $26
 $9
$241
 $117
 $21
 $74
 $19
 $76
 $43
 $26
 $11
Add (subtract):                 
Adjustments to reconcile net income to cash:                 
Non-cash operating activities(527) (529) (1) 26
 26
 (23) —
 (14) (7)(399) (293) (35) 12
 15
 (22) 13
 (18) (18)
Pension and non-pension postretirement benefit contributions(10) (29) (29) (2) 7
 51
 5
 (1) 6
(15) (31) (30) (1) 5
 51
 1
 (1) 6
Income taxes22
 263
 58
 (30) 16
 (25) (26) (5) 3
(23) 107
 90
 1
 5
 20
 (5) 11
 8
Changes in working capital and other noncurrent assets and liabilities(429) (187) (2) 10
 (83) (145) (63) (51) (17)(653) (367) (72) (40) (50) (93) (63) (31) 19
Option premiums received, net84
 84
 —
 —
 —
 —
 —
 —
 —
49
 49
 —
 —
 —
 —
 —
 —
 —
Collateral posted, net(392) (409) 24
 —
 (5) —
 —
 —
 —
(476) (520) 53
 —
 (6) —
 —
 —
 —
Net cash flows provided by (used in) operations$(971) $(635) $65
 $64
 $(12) $(68) $(50) $(45) $(6)
(Decrease) Increase in cash flows from operating activities$(1,276) $(938) $27
 $46
 $(12) $32
 $(11) $(13) $26
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 sixnine months ended JuneSeptember 30, 2019 and 2018 were as follows:
•
See Note 17 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statement of Cash Flows for additional information on non-cash operating activity.
•
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.
Cash Flows from Investing Activities (All Registrants)
The following table provides a summary of the change in cash provided by (used in)flows from investing activities for the sixnine months ended JuneSeptember 30, 2019 and 2018 by Registrant:
Change - Cash Provided by (Used in)Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Increase (Decrease) in cash flows from investing activitiesExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Capital expenditures$235
 $408
 $65
 $(36) $(108) $(69) $(11) $6
 $(57)$238
 $378
 $127
 $(60) $(175) $(18) $20
 $9
 $(53)
Proceeds from NDT fund sales, net175
 175
 —
 —
 —
 —
 —
 —
 —
180
 180
 —
 —
 —
 —
 —
 —
 —
Acquisitions of assets and businesses, net57
 57
 —
 —
 —
 —
 —
 —
 —
57
 57
 —
 —
 —
 —
 —
 —
 —
Proceeds from sales of assets and businesses(75) (75) —
 —
 —
 —
 —
 —
 —
(73) (73) —
 —
 —
 —
 —
 —
 —
Changes in intercompany money pool—
 6
 —
 —
 —
 —
 (38) —
 —
Other investing activities(5) 4
 —
 (1) (2) —
 (1) —
 2
(8) (1) 3
 1
 (4) 1
 (1) —
 1
Net cash flows provided by (used in) investing activities$387
 $575
 $65
 $(37) $(110) $(69) $(50) $6
 $(55)
Increase (Decrease) in cash flows from investing activities$394
 $541
 $130
 $(59) $(179) $(17) $19
 $9
 $(52)
Significant investing cash flow impacts for the Registrants for sixnine months ended JuneSeptember 30, 2019 and 2018 were as follows:
•
Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer to Liquidity and Capital Resources of the Exelon 2018 Form 10-K for additional information on projected capital expenditure spending.
•
During the sixnine months ended JuneSeptember 30, 2018, Exelon and Generation had proceeds of $79 million relating to the sale of its interest in an electrical contracting business.

Capital Expenditure Spending
As of JuneSeptember 30, 2019, there have been no material changes to the Registrants’ projected capital expenditures as disclosed in Liquidity and Capital Resources of the Exelon 2018 Form 10-K.
Cash Flows from Financing Activities (All Registrants)
The following table provides a summary of the change in cash provided by (used in)flows from financing activities for the sixnine months ended JuneSeptember 30, 2019 and 2018 by Registrant:
Change - Cash Provided by (Used in)Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Increase (Decrease) in cash flows from financing activitiesExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Changes in short-term borrowings, net$20
 $—
 $(17) $(50) $135
 $(49) $(14) $216
 $(251)$398
 $—
 $387
 $—
 $42
 $(31) $(66) $273
 $37
Long-term debt, net97
 (27) —
 125
 —
 10
 50
 (196) 156
(252) (69) (410) 125
 100
 13
 50
 (196) (116)
Changes in intercompany money pool—
 (46) —
 (181) —
 (4) —
 38
 —
—
 (46) —
 —
 —
 —
 —
 —
 —
Dividends paid on common stock(38) —
 (25) 113
 (7) —
 (22) (30) (5)(56) —
 (35) 32
 (12) —
 (45) (47) (54)
Distributions to member—
 (72) —
 —
 —
 (107) —
 —
 —
—
 14
 —
 —
 —
 (197) —
 —
 —
Contributions from parent/member—
 —
 (101) 104
 —
 48
 44
 (150) 155
—
 (54) (200) 103
 86
 46
 44
 (150) 155
Other financing activities64
 3
 —
 5
 —
 3
 1
 2
 (1)58
 9
 6
 16
 (5) 1
 1
 3
 (1)
Net cash flows provided by (used in) financing activities$143
 $(142) $(143) $116
 $128
 $(99) $59
 $(120) $54
Increase (Decrease) in cash flows from financing activities$148
 $(146) $(252) $276
 $211
 $(168) $(16) $(117) $21
Significant financing cash flow impacts for the Registrants for the sixnine months ended JuneSeptember 30, 2019 and 2018 were as follows:
•
Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 90 days. Refer to 11 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on short-term borrowings.
•
Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to 11 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on debt issuances. Refer to debt redemptions tables below for more information.
•
Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
•
Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2018 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
Debt
See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

During the sixnine months ended JuneSeptember 30, 2019, the following long-term debt was retired and/or redeemed:

Company(a) Type Interest Rate Maturity Amount Type Interest Rate Maturity Amount
Exelon Oracle Annual Lease Payment 3.95% May 1, 2024 $18
 Oracle Annual Lease Payment 3.95% May 1, 2024 $18
Generation Antelope Valley DOE Nonrecourse Debt 2.33% - 3.56%
 January 5, 2037 7
 Antelope Valley DOE Nonrecourse Debt 2.33% - 3.56%
 January 5, 2037 12
Generation Kennett Square Capital Lease 7.83% September 20, 2020 2
 Kennett Square Capital Lease 7.83% September 20, 2020 3
Generation Continental Wind Nonrecourse Debt 6.00% February 28, 2033 18
 Continental Wind Nonrecourse Debt 6.00% February 28, 2033 32
Generation Pollution control notes 2.50% March 1, 2019 23
 Pollution control notes 2.50% March 1, 2019 23
Generation Renewable Power Generation Nonrecourse Debt 4.11% March 31, 2035 3
 Renewable Power Generation Nonrecourse Debt 4.11% March 31, 2035 10
Generation Energy Efficiency Project Financing 3.46% April 30, 2019 39
 Energy Efficiency Project Financing 3.46% April 30, 2019 39
Generation ExGen Renewables IV Nonrecourse debt 3mL +3%
 November 30, 2024 38
 ExGen Renewables IV Nonrecourse debt 3mL +3%
 November 30, 2024 38
Generation Hannie Mae, LLC Defense Financing 4.12% November 30, 2019 1
 Hannie Mae, LLC Defense Financing 4.12% November 30, 2019 1
Generation Energy Efficiency Project Financing 3.72% July 31, 2019 25
Generation Nuclear fuel procurement contracts 3.15% September 30, 2020 36
Generation SolGen Nonrecourse Debt 3.93% September 30, 2036 2
Generation Energy Efficiency Project Financing 4.17% August 31, 2019 1
Generation Energy Efficiency Project Financing 3.53% March 31, 2020 1
Generation Energy Efficiency Project Financing 4.26% September 30, 2019 1
ComEd First Mortgage Bonds 2.15% January 15, 2019 300
 First Mortgage Bonds 2.15% January 15, 2019 300
Pepco Unsecured Tax-Exempt Bonds 6.20% September 1, 2022 110
 Unsecured Tax-Exempt Bonds 6.20% September 1, 2022 110
ACE Transition Bonds 5.55% October 20, 2023 9
 Transition Bonds 5.55% October 20, 2023 13
(a)On October 1, 2019, Generation redeemed $600 million of 5.20% 2009 Senior Notes due to maturity.
Antelope Valley’s nonrecourse debt of approximately $500$495 million was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of JuneSeptember 30, 2019 as a result of the PG&E bankruptcy filing on January 29, 2019. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the sixnine months ended JuneSeptember 30, 2019 and for the third quarter of 2019 were as follows:
Period Declaration Date Shareholder of Record Date Dividend Payable Date 
Cash per Share(a)
First Quarter 2019 February 5, 2019 February 20, 2019 March 8, 2019 $0.3625
Second Quarter 2019 April 30, 2019 May 15, 2019 June 10, 2019 $0.3625
Third Quarter 2019 July 30, 2019 August 15, 2019 September 10, 2019 $0.3625
_________
(a)Exelon's Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020.
Other
For the sixnine months ended JuneSeptember 30, 2019, other financing activities primarily consist of debt issuance costs. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.

Credit Matters (All Registrants)
The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include $9.8 billion in aggregate total commitments 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 secondthird quarter of 2019 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the

financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PART I. ITEM 1A. RISK FACTORS of the Exelon 2018 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flow from operating activities, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of JuneSeptember 30, 2019, it would have been required to provide incremental collateral of $1.5 billion to meet collateral obligations for derivatives, non-derivatives, normal purchases and normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within the $4.6$4.2 billion of available credit capacity of its revolver.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at JuneSeptember 30, 2019 and available credit facility capacity prior to any incremental collateral at JuneSeptember 30, 2019:
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$11
 $—
 $995
$10
 $—
 $995
PECO1
 31
 600
—
 28
 600
BGE12
 31
 594
12
 26
 594
Pepco11
 —
 290
10
 —
 290
DPL7
 12
 300
6
 11
 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. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See 11 — Debt and Credit Agreements and Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ short-term borrowing activity.
See Note 13 — Debt and Credit Agreements and Note 22 — Commitments and Contingencies of the Exelon 2018 Form 10-K for additional information on the Registrants’ credit facilities.
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.

Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of JuneSeptember 30, 2019, are presented in the following table:
Exelon Intercompany Money Pool During the Three Months Ended June 30, 2019 As of June 30, 2019 During the Three Months Ended September 30, 2019 As of September 30, 2019
Contributed (Borrowed) 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
Exelon Corporate $262
 $—
 $111
 $260
 $—
 $206
Generation 179
 —
 179
 212
 —
 —
PECO —
 (67) (52) 7
 (85) —
BSC —
 (374) (290) —
 (338) (251)
PHI Corporate —
 (5) (3) —
 (10) (10)
PCI 60
 —
 55
 55
 —
 55
PHI Intercompany Money Pool During the Three Months Ended June 30, 2019 As of June 30, 2019 During the Three Months Ended September 30, 2019 As of September 30, 2019
Contributed (Borrowed) 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
PHI Corporate $2
 $(2) $2
Pepco 38
 —
 38
 63
 —
 —
DPL —
 (38) (38) —
 (46) —
ACE —
 (29) —
PHISCO 4
 —
 2
 2
 —
 2
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 2019.2022. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

Regulatory Authorizations
ComEd, PECO, BGE, Pepco, DPL and ACE are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
 As of June 30, 2019 As of September 30, 2019
 
Short-term Financing Authority(a)
 
Remaining Long-term Financing Authority(a)
 
Short-term Financing Authority(a)(b)
 
Remaining Long-term Financing Authority(a)
Commission Expiration Date AmountCommission Expiration Date AmountCommission Expiration Date AmountCommission Expiration Date Amount
ComEd(b)(c)
 FERC December 31, 2019 $2,500
 ICC August 1, 2021 $693
 FERC December 31, 2019 $2,500
 ICC August 1, 2021 $693
PECO(c)
 FERC December 31, 2019 1,500
 PAPUC December 31, 2021 1,900
 FERC December 31, 2019 1,500
 PAPUC December 31, 2021 1,575
BGE FERC December 31, 2019 700
 MDPSC N/A 400
 FERC December 31, 2019 700
 MDPSC N/A —
Pepco FERC December 31, 2019 500
 MDPSC / DCPSC December 31, 2020 141
 FERC December 31, 2019 500
 MDPSC / DCPSC December 31, 2020 141
DPL FERC December 31, 2019 500
 MDPSC / DPSC December 31, 2020 150
 FERC December 31, 2019 500
 MDPSC / DPSC December 31, 2020 150
ACE NJBPU December 31, 2019 350
 NJBPU December 31, 2020 200
 NJBPU December 31, 2019 350
 NJBPU December 31, 2020 200
_________
(a)
Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.
(b)On October 15, 2019, ComEd, PECO, BGE, Pepco and DPL filed applications with FERC and on September 12, 2019, ACE filed an application with NJBPU for renewal of their short-term financing authority through December 31, 2021. ComEd, PECO, BGE, Pepco, DPL and ACE expect approval of the applications before the end of the year.
(c)ComEd had $693 million available in new money long-term debt financing authority from the ICC as of JuneSeptember 30, 2019 and has an expiration date of August 1, 2021.


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 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 2018 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 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional 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 2018 Form 10-K.

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 2018 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 is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel and other commodities.
Generation
Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards and options, with approved counterparties to hedge anticipated exposures. Generation uses derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 2019 through 2021.
As of JuneSeptember 30, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 92%-95%96%-99%, 70%-73%84%-87% and 40%-43%54%-57% for 2019, 2020 and 2021, respectively. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on JuneSeptember 30, 2019 market conditions and hedged position would be a decrease in pre-tax net incomeimmaterial for 2019, and decreases of approximately, $19 million, $230$88 million and $533$399 million, respectively, for 2019, 2020 and 2021. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Fuel Procurement
Approximately 62%63% of Generation’s uranium concentrate requirements from 2019 through 2023 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s financial statements.
Utility Registrants
There have been no significant changes or additions to the Utility Registrants exposures to commodity price risk that were described in ITEM 1A. RISK FACTORS of Exelon’s 2018 Annual Report on Form 10-K. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding commodity price risk exposure.
Trading and Non-Trading Marketing Activities
The following table detailing Exelon’s, Generation’s and ComEd’s trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

The following table provides detail on changes in Exelon’s, Generation’s and ComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, 2018 to JuneSeptember 30, 2019. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all NPNS contracts and does not segregate proprietary trading activity. See Note 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 JuneSeptember 30, 2019 and December 31, 2018.
Exelon Generation ComEdExelon Generation ComEd
Total mark-to-market energy contract net assets (liabilities) at December 31, 2018(a)
$299
 $548
 $(249)$299
 $548
 $(249)
Total change in fair value during 2019 of contracts recorded in results of operations(200) (200) —
(273) (273) —
Reclassification to realized of contracts recorded in results of operations113
 113
 —
215
 215
 —
Changes in fair value — recorded through regulatory assets and liabilities(b)
(24) —
 (24)(31) —
 (31)
Changes in allocated collateral399
 399
 —
364
 364
 —
Net option premium paid/(received)(48) (48) —
(13) (13) —
Option premium amortization(43) (43) —
(21) (21) —
Upfront payments and amortizations(c)
(32) (32) —
(73) (73) —
Total mark-to-market energy contract net assets (liabilities) at June 30, 2019(a)
$464
 $737
 $(273)
Total mark-to-market energy contract net assets (liabilities) at September 30, 2019(a)
$467
 $747
 $(280)
_________
(a)Amounts are shown net of collateral paid to and received from counterparties.
(b)For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of JuneSeptember 30, 2019, ComEd recorded a regulatory liability of $273$280 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the sixnine months ended JuneSeptember 30, 2019, ComEd recorded $24$31 million of decreases in fair value and an increase for realized losses due to settlements of $145$17 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 amortizations
Fair Values
The following tables present maturity and source of fair value for Exelon, Generation and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 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.

Exelon
Maturities Within Total Fair
Value		Maturities Within Total Fair
Value
2019 2020 2021 2022 2023 2024 and Beyond 2019 2020 2021 2022 2023 2024 and Beyond 
Normal Operations, Commodity derivative contracts(a)(b):
                          
Actively quoted prices (Level 1)$(73) $(75) $(10) $(8) $13
 $12
 $(141)$(22) $(105) $(25) $(13) $9
 $9
 $(147)
Prices provided by external sources (Level 2)44
 (47) 24
 (16) —
 —
 5
76
 (1) 47
 (10) —
 —
 112
Prices based on model or other valuation methods (Level 3)(c)
221
 405
 96
 5
 (9) (118) 600
65
 442
 116
 33
 (6) (148) 502
Total$192
 $283
 $110
 $(19) $4
 $(106) $464
$119
 $336
 $138
 $10
 $3
 $(139) $467
_________
(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 $756$721 million at JuneSeptember 30, 2019.
(c)Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Generation
Maturities Within Total Fair
Value		Maturities Within Total Fair
Value
2019 2020 2021 2022 2023 2024 and Beyond 2019 2020 2021 2022 2023 2024 and Beyond 
Normal Operations, Commodity derivative contracts(a)(b):
                          
Actively quoted prices (Level 1)$(73) $(75) $(10) $(8) $13
 $12
 $(141)$(22) $(105) $(25) $(13) $9
 $9
 $(147)
Prices provided by external sources (Level 2)44
 (47) 24
 (16) —
 —
 5
76
 (1) 47
 (10) —
 —
 112
Prices based on model or other valuation methods (Level 3)235
 433
 124
 33
 18
 30
 873
75
 469
 143
 60
 21
 14
 782
Total$206
 $311
 $138
 $9
 $31
 $42
 $737
$129
 $363
 $165
 $37
 $30
 $23
 $747
_________
(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 $756$721 million at JuneSeptember 30, 2019.
ComEd
Maturities Within Total Fair
Value		Maturities Within Total Fair
Value
2019 2020 2021 2022 2023 2024 and Beyond 2019 2020 2021 2022 2023 2024 and Beyond 
Commodity derivative contracts(a):
                          
Prices based on model or other valuation methods (Level 3)$(14) $(28) $(28) $(28) $(27) $(148) $(273)$(10) $(27) $(27) $(27) $(27) $(162) $(280)
_________
(a)Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the

fair value of contracts at the reporting date. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for detailed discussion of credit risk.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchases and normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of JuneSeptember 30, 2019. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs and commodity exchanges, which are discussed below. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $70$68 million, $30 million, $32 million, $39 million, $15 million and $8 million as of JuneSeptember 30, 2019, respectively.
Rating as of June 30, 2019 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, 2019 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 $859
 $12
 $847
 $2
 $249
 $693
 $10
 $683
 $—
 $—
Non-investment grade 30
 11
 19
 

 

 74
 38
 36
 

 

No external ratings                    
Internally rated — investment grade 204
 1
 203
 

 

 297
 1
 296
 

 

Internally rated — non-investment grade 117
 11
 106
 

 

 175
 24
 151
 

 

Total $1,210
 $35
 $1,175
 $2
 $249
 $1,239
 $73
 $1,166
 $—
 $—
 Maturity of Credit Risk Exposure Maturity of Credit Risk Exposure
Rating as of June 30, 2019 
Less than
2 Years
 2-5 Years 
Exposure
Greater than
5 Years
 
Total Exposure
Before Credit
Collateral
Rating as of September 30, 2019 
Less than
2 Years
 2-5 Years 
Exposure
Greater than
5 Years
 
Total Exposure
Before Credit
Collateral
Investment grade $795
 $53
 $11
 $859
 $649
 $38
 $6
 $693
Non-investment grade 30
 —
 —
 30
 76
 (2) —
 74
No external ratings                
Internally rated — investment grade 135
 37
 32
 204
 234
 35
 28
 297
Internally rated — non-investment grade 111
 1
 5
 117
 148
 16
 11
 175
Total $1,071
 $91
 $48
 $1,210
 $1,107
 $87
 $45
 $1,239
Net Credit Exposure by Type of Counterparty As of
June 30, 2019		 As of
September 30, 2019
Financial institutions $3
 $1
Investor-owned utilities, marketers, power producers 810
 875
Energy cooperatives and municipalities 302
 255
Other 60
 35
Total $1,175
 $1,166
_________
(a)As of JuneSeptember 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $25$18 million of cash and $9$55 million of letters of credit.

The Utility Registrants
There have been no significant changes or additions to the Utility Registrants exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 2018 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.
Credit-Risk-Related Contingent Features (All Registrants)
Generation
As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase of electricity, natural gas and other commodities. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.
Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s financial statements. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See Note 13 — Debt and Credit Agreements of the Exelon Form 10-K for additional information.
Utility Registrants
As of JuneSeptember 30, 2019, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Interest Rate and Foreign Exchange Risk (Exelon and Generation)
Exelon and Generation use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon and Generation may also utilize interest rate swaps to manage their interest rate exposure. A hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $3$4 million decrease in Exelon pre-tax income for the sixnine months ended JuneSeptember 30, 2019. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Equity Price Risk (Exelon and Generation)
Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of JuneSeptember 30, 2019, Generation’s NDT funds are reflected at fair value in its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment

investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $563$570 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Liquidity and Capital Resources section of ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information of equity price risk as a result of the current capital and credit market conditions.
Item 4.    Controls and Procedures
During the secondthird quarter of 2019, 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 JuneSeptember 30, 2019, 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 secondthird quarter of 2019 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.
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 2018 Form 10-K and (b) Notes 6 — Regulatory Matters and 16 — 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 JuneSeptember 30, 2019, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2018 Form 10-K in ITEM 1A. RISK FACTORS.
Item 4.    Mine Safety Disclosures
All Registrants
Not applicable to the Registrants.

Item 5.    Other Information
Generation - Second Amended and Restated Operating Agreement
On October 30, 2019, Exelon, as sole member of Generation, executed the Second Amended and ComEd—SubpoenaRestated Operating Agreement of Generation solely to update certain administrative provisions.  This summary is qualified by reference to the complete text of the Second Amended and Restated Operating Agreement of Generation, attached as Exhibit 3.1 to this Report. 
Exelon and ComEd received a grand jury subpoena from the U.S. Attorney’s Office for the Northern District of Illinois requiring production of information concerning their lobbying activities in the State of Illinois. Exelon and ComEd have pledged to cooperate fully and are cooperating fully with the U.S. Attorney’s Office in expeditiously providing the requested information.
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 Registrant and its subsidiaries on a consolidated basis and the relevant Registrant agrees to furnish a copy of any such instrument to the Commission upon request.
Exhibit
No.
Description
3.1*
Second Amended and Restated Operating Agreement of Exelon Generation Company, LLC
4.1
Atlantic City Electric CompanyOne Hundred and Seventeenth Supplemental Indenture Supplemental, dated as of May 2,August 15, 2019 from PECO Energy Company to the Mortgage and Deed of Trust, dated January 15, 1937U.S. Bank National Association, as trustee (File No. 001-03559,000-16844, Form 8-K dated May 21, 2019, Exhibit 4.3)September 10, 2019)
  
4.2
Potomac Electric Power Company Supplemental Indenture, dated as of May 2,September 1, 2019, with respect to the Mortgagebetween Baltimore Gas and Deed of Trust, dated July 1, 1936Electric Company and U.S. Bank National Association, as trustee (File No. 001-01072,001-01910, Form 8-K dated June 13,September 12, 2019, Exhibit 4.2)4.1)
  
4.310.1*
Exempt Facilities LoanExelon Corporation Non-Employee Director Deferred Stock Unit Plan, as amended and restated effective September 25, 2019.
10.2*
Amended Form of Restricted Stock Award Agreement datedunder Exelon Corporation Long-Term Incentive Plan
10.3*
Exelon Corporation Employee Stock Purchase Plan, as of June 1, 2019 between the Maryland Economic Developmentamended and restated effective September 25, 2019.
10.4*
Exelon Corporation Employee Stock Purchase Plan for Unincorporated Subsidiaries, as amended and Potomac Electric Power Company (File No. 001-01072, Form 8-K dated June 27, 2019, Exhibit 4.1)restated effective September 25, 2019.
10.5*
Exelon Corporation Stock Deferral Plan, as amended and restated effective September 25, 2019.
  
101.INSXBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
  
101.SCHXBRL Taxonomy Extension Schema Document.
  
101.CALXBRL Taxonomy Extension Calculation Linkbase Document.
  
101.DEFXBRL Taxonomy Extension Definition Linkbase Document.
  
101.LABXBRL Taxonomy Extension Label Linkbase Document.
  
101.PREXBRL Taxonomy Extension Presentation Linkbase Document.
*Filed herewith

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 JuneSeptember 30, 2019 filed by the following officers for the following companies:
31-1
— Filed by Christopher M. Crane for Exelon Corporation
  
31-2
— Filed by Joseph 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 Joseph Dominguez for Commonwealth Edison Company
  
31-6
— Filed by Jeanne M. Jones for Commonwealth Edison Company
  
31-7
— Filed by Michael A. Innocenzo for PECO Energy Company
  
31-8
— Filed by Robert 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 Phillip S. Barnett for Pepco Holdings LLC
  
31-13
— Filed by David M. Velazquez for Potomac Electric Power Company
  
31-14
— Filed by Phillip S. Barnett for Potomac Electric Power Company
  
31-15
— Filed by David M. Velazquez for Delmarva Power & Light Company
  
31-16
— Filed by Phillip S. Barnett for Delmarva Power & Light Company
  
31-17
— Filed by David M. Velazquez for Atlantic City Electric Company
  
31-18
— Filed by Phillip S. Barnett for Atlantic City Electric Company

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 JuneSeptember 30, 2019 filed by the following officers for the following companies:
  
32-1
— Filed by Christopher M. Crane for Exelon Corporation
  
32-2
— Filed by Joseph 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 Joseph Dominguez for Commonwealth Edison Company
  
32-6
— Filed by Jeanne M. Jones for Commonwealth Edison Company
  
32-7
— Filed by Michael A. Innocenzo for PECO Energy Company
  
32-8
— Filed by Robert 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 Phillip S. Barnett for Pepco Holdings LLC
  
32-13
— Filed by David M. Velazquez for Potomac Electric Power Company
  
32-14
— Filed by Phillip S. Barnett for Potomac Electric Power Company
  
32-15
— Filed by David M. Velazquez for Delmarva Power & Light Company
  
32-16
— Filed by Phillip S. Barnett for Delmarva Power & Light Company
  
32-17
— Filed by David M. Velazquez for Atlantic City Electric Company
  
32-18
— Filed by Phillip S. Barnett for Atlantic City Electric Company

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/    JOSEPH NIGRO
Christopher M. Crane Joseph Nigro
President and Chief Executive Officer
(Principal Executive Officer) and Director
 
Senior Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
   
/s/    FABIAN E. SOUZA  
Fabian E. Souza  
Senior Vice President and Corporate Controller
(Principal Accounting Officer)
  
August 1,October 31, 2019

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)
  
August 1,October 31, 2019

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/    JOSEPH DOMINGUEZ /s/    JEANNE M. JONES
Joseph Dominguez Jeanne M. Jones
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)
  
August 1,October 31, 2019

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/    MICHAEL A. INNOCENZO /s/    ROBERT J. STEFANI
Michael A. Innocenzo Robert J. Stefani
President and Chief Executive Officer
(Principal Executive Officer)
 
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)
  
August 1,October 31, 2019


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
(Principal Financial Officer)
   
 /s/ ANDREW W. HOLMES  
Andrew W. Holmes  
Vice President and Controller
(Principal Accounting Officer)
  
August 1,October 31, 2019


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/    PHILLIP S. BARNETT
David M. Velazquez Phillip 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)
  
August 1,October 31, 2019


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/    PHILLIP S. BARNETT
David M. Velazquez Phillip 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)		  
August 1,October 31, 2019


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/    PHILLIP S. BARNETT
David M. Velazquez Phillip 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)		  
August 1,October 31, 2019


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/    PHILLIP S. BARNETT
David M. Velazquez Phillip 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)		  
August 1,October 31, 2019

202