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:OysterCreekMember us-gaap:OperatingExpenseMember 2019-04-01 2019-06-30 0001109357 exc:ExelonGenerationCoLLCMember exc:CommodityDerivativeAssetsMember us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember us-gaap:FairValueMeasurementsRecurringMember 2018-12-31 0001109357 exc:ExelonGenerationCoLLCMember exc:RabbiTrustInvestmentsMember us-gaap:FairValueMeasuredAtNetAssetValuePerShareMember us-gaap:FairValueMeasurementsRecurringMember 2019-09-30 0001109357 exc:GenerationErcotMember 2019-01-01 2019-09-30 0001109357 exc:BaltimoreGasAndElectricCompanyMember us-gaap:OperatingSegmentsMember us-gaap:ElectricityUsRegulatedMember us-gaap:RegulatedOperationMember 2019-07-01 2019-09-30
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31,September 30, 2019
or
o☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission
File Number
 Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number IRS Employer Identification Number
     
1-16169001-16169 EXELON CORPORATION 23-2990190
  
(a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago, Illinois 60680-5379
(800) 483-3220
  
     
333-85496 EXELON GENERATION COMPANY, LLC 23-3064219
  
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348-2473
(610) 765-5959
  
     
1-1839001-01839 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
  
     
1-1910001-01910 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;CORPORATION:    
Common Stock, without par value EXC New York and Chicago
Series A Junior Debt Subordinated DebenturesEXC22New YorkThe Nasdaq Stock Market LLC
     
PECO ENERGY COMPANY:    
Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company EXC/28 New York Stock Exchange


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.  Yesx  No  o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yesx  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 Corporationx



☐
Exelon Generation Company, LLC
Large Accelerated Filer
☐
Accelerated Filer
☐		Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Commonwealth Edison Company
Large Accelerated Filer
☐
Accelerated Filer
☐		Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
PECO Energy Company
Large Accelerated Filer
☐
Accelerated Filer
☐		Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Baltimore Gas and Electric Company
Large 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. o☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  o☐  No  x
The number of shares outstanding of each registrant’s common stock as of March 31,September 30, 2019 was:
Exelon Corporation Common Stock, without par value970,954,879972,108,865
Exelon Generation Company, LLCnot applicable
Commonwealth Edison Company Common Stock, $12.50 par value127,021,331127,021,343
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
15
Consolidated Statements of Cash Flows
16
 
Consolidated Balance SheetsStatements of Cash Flows
17
 
Consolidated Balance Sheets
18
Consolidated Statements of Changes in Equity
19
Commonwealth Edison Company
Consolidated Statements of Operations and Comprehensive Income
20
 
Consolidated Statements of Cash FlowsCommonwealth Edison Company
21
 
Consolidated Balance SheetsStatements of Operations and Comprehensive Income
22
 
Consolidated Statements of Changes in Shareholders' EquityCash Flows
23
Consolidated Balance Sheets
24
 
PECO Energy Company
Consolidated Statements of Operations and Comprehensive Income
25
Consolidated Statements of Cash FlowsChanges in Shareholders' Equity
26
 
PECO Energy Company
Consolidated Balance SheetsStatements of Operations and Comprehensive Income
27
 
Consolidated Statements of Changes in Shareholder's EquityCash Flows
28
Consolidated Balance Sheets
29
 
Baltimore Gas and Electric Company
Consolidated Statements of Operations and Comprehensive Income
30
Statements of Cash FlowsChanges in Shareholder's Equity
31
 
Balance SheetsBaltimore Gas and Electric Company
Statements of Operations and Comprehensive Income
32
 
Statements of Changes in Shareholder's EquityCash Flows
33
Balance Sheets
34
 
Pepco Holdings LLC
Consolidated Statements of Operations and Comprehensive Income
35
Consolidated Statements of Cash FlowsChanges in Shareholder's Equity
36
 
Pepco Holdings LLC
Consolidated Balance SheetsStatements of Operations and Comprehensive Income
37
 
Consolidated Statements of Cash Flows
38
Consolidated Balance Sheets
39
Consolidated Statements of Changes in Equity
3941

 Page No.
 
Potomac Electric Power Company
 
 
Statements of Operations and Comprehensive Income
40
Statements of Cash Flows
41
Balance Sheets
42
 
Statements of Changes in Shareholder's EquityCash Flows
43
Balance Sheets
44
 
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
45
Statements of Cash FlowsChanges in Shareholder's Equity
46
 
Balance SheetsDelmarva Power & Light Company
Statements of Operations and Comprehensive Income
47
 
Statements of Changes in Shareholder’s EquityCash Flows
48
Balance Sheets
49
 
Atlantic City Electric Company
Consolidated Statements of Operations and Comprehensive Income
50
Consolidated Statements of Cash FlowsChanges in Shareholder’s Equity
51
 
Atlantic City Electric Company
Consolidated Balance SheetsStatements of Operations and Comprehensive Income
52
 
Consolidated Statements of Changes in Shareholder’s EquityCash Flows
53
Consolidated Balance Sheets
54
 
Combined Notes to Consolidated Financial Statements
55
1. Significant Accounting Policies of Changes in Shareholder’s Equity
56
 
2. Variable Interest EntitiesCombined Notes to Consolidated Financial Statements
5857
 
1. Significant Accounting Policies
57
2. Variable Interest Entities
59
3. Mergers, Acquisitions and Dispositions
63
 
4. Revenue from Contracts with Customers
64
 
5. Leases
6665
 
6. Regulatory Matters
69
 
7. Impairment of Long-Lived AssetsAsset Impairments
7375
 
8. Early Plant Retirements
73
9. Fair Value of Financial Assets and Liabilities
76
 
10. Derivative9. Fair Value of Financial InstrumentsAssets and Liabilities
9378
 
10. Derivative Financial Instruments
89
11. Debt and Credit Agreements
96
12. Income Taxes
98
13. Nuclear Decommissioning
101
14. Retirement Benefits
103
 
12.15. Changes in Accumulated Other Comprehensive Income Taxes
105
 
13. Nuclear Decommissioning16. Commitments and Contingencies
107106
 
14. Retirement Benefits
108
15. Changes in Accumulated Other Comprehensive Income
110
16. Commitments and Contingencies17. Supplemental Financial Information
113
 
17. Supplemental Financial18. Segment Information
120
18. Segment Information
126119

 Page No.
ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
135
 
Exelon Corporation
135
 
Executive Overview
135
 
Financial Results of Operations
136
 
Significant 2019 Transactions and Developments
137
Exelon's Strategy and Outlook for 2018 and Beyond
140
 
Liquidity Considerations
141
Other Key Business Drivers and Management Strategies
142143
 
Critical Accounting Policies and Estimates
146
Results of Operations By Registrant
146
Exelon Generation Company, LLC
147
 
Results of Operations By RegistrantCommonwealth Edison Company
147154
 
Exelon GenerationPECO Energy Company LLC
148157
 
Commonwealth EdisonBaltimore Gas and Electric Company
153161
 
PECO Energy Company
156
Baltimore Gas and Electric Company
160
Pepco Holdings LLC
163
Potomac Electric Power Company
164
 
DelmarvaPotomac Electric Power & Light Company
167165
 
Atlantic City ElectricDelmarva Power & Light Company
171168
 
Liquidity and Capital ResourcesAtlantic City Electric Company
174173
 
Liquidity and Capital Resources
177
Contractual Obligations and Off-Balance Sheet Arrangements
180184
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
181185
ITEM 4.
CONTROLS AND PROCEDURES
187190
PART II.
OTHER INFORMATION
188190
ITEM 1.
LEGAL PROCEEDINGS
188190
ITEM 1A.
RISK FACTORS
188190
ITEM 4.
MINE SAFETY DISCLOSURES
188190
ITEM 5.
OTHER INFORMATION
188191
ITEM 6.
EXHIBITS
189191
SIGNATURES
192
Exelon Corporation
192
Exelon Generation Company, LLC
193
Commonwealth Edison Company
194
 
PECO EnergyExelon Corporation
194
Exelon Generation Company, LLC
195
 
Baltimore Gas and ElectricCommonwealth Edison Company
196
 
Pepco Holdings LLCPECO Energy Company
197
 
PotomacBaltimore Gas and Electric Power Company
198
 
Delmarva Power & Light CompanyPepco Holdings LLC
199
 
Potomac Electric Power Company
200
Delmarva Power & Light Company
201
Atlantic City Electric Company
200202

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
CAISOCERCLA California Independent System OperatorComprehensive 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 Public Service Commission
DOE United States Department of Energy
DOEE Department of Energy & Environment
DOJ United States Department of Justice
DPSC Delaware Public Service Commission
DSPDefault Service Provider
EDF Electricite de France SA and its subsidiaries
EIMA Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EmPowerA Maryland demand-side management program for Pepco and DPL
EPA United States Environmental Protection Agency
EPSA Electric Power Supply Association
ERCOT Electric Reliability Council of Texas
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
GHGGreenhouse Gas
GSA Generation Supply Adjustment
IBEWInternational Brotherhood of Electrical Workers
ICC Illinois Commerce Commission
ICE Intercontinental Exchange
Illinois EPAIllinois Environmental Protection Agency
IPAIllinois Power Agency
IRCInternal Revenue Code
IRSInternal Revenue Service

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations  
Illinois EPAIllinois Environmental Protection Agency
Illinois Settlement LegislationLegislation enacted in 2007 affecting electric utilities in Illinois
IPAIllinois Power Agency
IRCInternal Revenue Code
IRSInternal Revenue Service
ISO Independent System Operator
ISO-NE Independent System Operator New England Inc.
ISO-NY Independent System Operator New York
LIBOR London Interbank Offered Rate
MATSU.S. EPA Mercury and Air Toxics Rule
MBRMarket Based Rates Incentive
MDE Maryland Department of the Environment
MDPSC Maryland Public Service Commission
MGP Manufactured Gas Plant
MISO Midcontinent Independent System Operator, Inc.
mmcf Million Cubic Feet
Moody’sMoody’s Investor Service
MOPR Minimum Offer Price Rule
MW Megawatt
NAAQS National Ambient Air Quality Standards
NAVNet Asset Value
NDT Nuclear Decommissioning Trust
NEIL Nuclear Electric Insurance Limited
NERC North American Electric Reliability Corporation
NJBPU New Jersey Board of Public Utilities
NLRBNational Labor Relations Board
Non-Regulatory Agreements Units Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOSA Nuclear Operating Services Agreement
NPDESNPNS National Pollutant Discharge Elimination SystemNormal Purchase Normal Sale scope exception
NRC Nuclear Regulatory Commission
NSPSNew Source Performance Standards
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
PGC Purchased Gas Cost Clause
PG&EPacific Gas and Electric Company
PJM PJM Interconnection, LLC
POLRProvider of Last Resort
PPAPower Purchase Agreement
PPEProperty, plant and equipment
Price-Anderson ActPrice-Anderson Nuclear Industries Indemnity Act of 1957
PRPPotentially Responsible Parties
PSDARPost-Shutdown Decommissioning Activities Report
PSEGPublic Service Enterprise Group Incorporated
RECRenewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
RNFRevenues Net of Purchased Power and Fuel Expense

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations  
POLRProvider of Last Resort
PORPurchase of Receivables
PPAPower Purchase Agreement
Price-Anderson ActPrice-Anderson Nuclear Industries Indemnity Act of 1957
PRPPotentially Responsible Parties
PSEGPublic Service Enterprise Group Incorporated
RCRAResource Conservation and Recovery Act of 1976, as amended
RECRenewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement Units Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
Rider Reconcilable Surcharge Recovery Mechanism
RMC Risk Management Committee
ROE Return on equity
ROU Right-of-use
RPSRenewable Energy Portfolio Standards
RSSA Reliability Support Services Agreement
RTO Regional Transmission Organization
S&PStandard & Poor’s Ratings Services
SEC United States Securities and Exchange Commission
SERC SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SNF Spent Nuclear Fuel
SOS Standard Offer Service
SPPSouthwest Power Pool
TCJA Tax Cuts and Jobs Act
Transition Bond ChargeRevenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees
Transition Bonds Transition Bonds issued by ACE Funding
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
March 31,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions, except per share data)2019 20182019 2018 2019 2018
Operating revenues          
Competitive businesses revenues$4,979
 $5,113
$4,499
 $4,971
 $13,436
 $14,387
Rate-regulated utility revenues4,503
 4,570
4,510
 4,457
 12,758
 12,824
Revenues from alternative revenue programs(5) 10
(80) (25) (98) (41)
Total operating revenues9,477
 9,693
8,929
 9,403
 26,096
 27,170
Operating expenses          
Competitive businesses purchased power and fuel3,204
 3,289
2,648
 2,977
 8,142
 8,542
Rate-regulated utility purchased power and fuel1,349
 1,438
1,304
 1,355
 3,589
 3,832
Operating and maintenance2,189
 2,384
2,072
 2,346
 6,419
 7,036
Depreciation and amortization1,075
 1,091
1,083
 1,105
 3,237
 3,284
Taxes other than income445
 446
452
 469
 1,316
 1,342
Total operating expenses8,262

8,648
7,559

8,252

22,703

24,036
Gain on sales of assets and businesses3
 56
(Loss) gain on sales of assets and businesses(17) (5) 19
 55
Operating income1,218

1,101
1,353

1,146

3,412

3,189
Other income and (deductions)
 
    
 
Interest expense, net(397) (365)(403) (387) (1,202) (1,119)
Interest expense to affiliates(6) (6)(6) (6) (19) (19)
Other, net467
 (28)158
 194
 837
 212
Total other income and (deductions)64

(399)(251)
(199)
(384)
(926)
Income before income taxes1,282
 702
1,102
 947
 3,028
 2,263
Income taxes310
 59
172
 137
 626
 262
Equity in losses of unconsolidated affiliates(6) (7)(170) (10) (182) (22)
Net income966

636
760

800

2,220

1,979
Net income attributable to noncontrolling interests59
 51
Net (loss) income attributable to noncontrolling interests(12) 67
 56
 121
Net income attributable to common shareholders$907

$585
$772

$733

$2,164

$1,858
Comprehensive income, net of income taxes          
Net income$966
 $636
$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)(16) (17) (49) (50)
Actuarial loss reclassified to periodic benefit cost36
 61
37
 62
 111
 186
Pension and non-pension postretirement benefit plan valuation adjustment(38) 18
6
 5
 (32) 22
Unrealized gain on cash flow hedges—
 8
—
 —
 —
 12
Unrealized (loss) gain on investments in unconsolidated affiliates(2) 1
Unrealized gain on foreign currency translation2
 1
Other comprehensive (loss) income(18)
72
Unrealized gain on investments in unconsolidated affiliates5
 —
 1
 3
Unrealized (loss) gain on foreign currency translation(2) 2
 2
 (4)
Other comprehensive income30

52

33

169
Comprehensive income948

708
790

852

2,253

2,148
Comprehensive income attributable to noncontrolling interests58
 52
Comprehensive (loss) income attributable to noncontrolling interests(9) 67
 57
 123
Comprehensive income attributable to common shareholders$890
 $656
$799
 $785
 $2,196
 $2,025
          
Average shares of common stock outstanding:          
Basic971
 966
973
 968
 972
 967
Assumed exercise and/or distributions of stock-based awards1
 2
1
 2
 1
 2
Diluted(a)
972
 968
974
 970
 973
 969
          
Earnings per average common share:          
Basic$0.93
 $0.61
$0.79
 $0.76
 $2.23
 $1.92
Diluted$0.93
 $0.60
$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 nine months ended March 31,September 30, 2019 and approximately 52 million and 3 million for the three and nine months ended March 31, 2018.September 30, 2018, respectively.

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities      
Net income$966
 $636
$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 amortization1,460
 1,501
4,393
 4,511
Impairment of long-lived assets7
 —
Asset impairments174
 49
Gain on sales of assets and businesses—
 (56)(15) (55)
Deferred income taxes and amortization of investment tax credits187
 (14)412
 97
Net fair value changes related to derivatives31
 259
96
 67
Net realized and unrealized (gains) losses on NDT funds(308) 68
Net realized and unrealized gains on NDT funds(467) (21)
Other non-cash operating activities127
 240
460
 804
Changes in assets and liabilities:      
Accounts receivable79
 133
445
 (167)
Inventories128
 167
(94) (24)
Accounts payable and accrued expenses(764) (451)(671) 84
Option premiums received (paid), net6
 (27)13
 (36)
Collateral posted, net(101) (214)
Collateral (posted) received, net(254) 222
Income taxes141
 86
143
 166
Pension and non-pension postretirement benefit contributions(328) (331)(377) (362)
Other assets and liabilities(587) (495)(1,079) (639)
Net cash flows provided by operating activities1,044

1,502
5,399

6,675
Cash flows from investing activities      
Capital expenditures(1,873) (1,880)(5,259) (5,497)
Proceeds from NDT fund sales3,713
 1,189
8,443
 6,379
Investment in NDT funds(3,666) (1,248)(8,437) (6,553)
Acquisition of assets and businesses, net—
 (57)
Proceeds from sales of assets and businesses8
 79
17
 90
Other investing activities32
 3
21
 29
Net cash flows used in investing activities(1,786)
(1,857)(5,215)
(5,609)
Cash flows from financing activities      
Changes in short-term borrowings540
 726
430
 (218)
Proceeds from short-term borrowings with maturities greater than 90 days—
 1
—
 126
Repayments on short-term borrowings with maturities greater than 90 days—
 (1)(125) (1)
Issuance of long-term debt402
 1,130
1,576
 2,664
Retirement of long-term debt(352) (1,241)(644) (1,480)
Dividends paid on common stock(352) (333)(1,055) (999)
Proceeds from employee stock plans51
 12
94
 67
Other financing activities(14) (30)(63) (94)
Net cash flows provided by financing activities275

264
213

65
Decrease in cash, cash equivalents and restricted cash(467) (91)
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$1,314

$1,099
$2,178

$2,321
   
Supplemental cash flow information   
Decrease in capital expenditures not paid$(96) $(175)
Increase in PPE related to ARO update344
 67

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$880
 $1,349
$1,683
 $1,349
Restricted cash and cash equivalents223
 247
309
 247
Accounts receivable, net      
Customer4,564
 4,607
Other1,062
 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 assets652
 804
601
 804
Unamortized energy contract assets49
 48
49
 48
Inventories, net      
Fossil fuel and emission allowances179
 334
325
 334
Materials and supplies1,380
 1,351
1,458
 1,351
Regulatory assets1,191
 1,222
1,194
 1,222
Assets held for sale890
 904
18
 904
Other1,406
 1,238
1,296
 1,238
Total current assets12,476

13,360
12,206

13,360
Property, plant and equipment, net77,460
 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 assets8,222
 8,237
8,122
 8,237
Nuclear decommissioning trust funds12,302
 11,661
12,706
 11,661
Investments620
 625
471
 625
Goodwill6,677
 6,677
6,677
 6,677
Mark-to-market derivative assets454
 452
487
 452
Unamortized energy contract assets365
 372
353
 372
Other3,017
 1,575
3,123
 1,575
Total deferred debits and other assets31,657

29,599
31,939

29,599
Total assets(a)
$121,593

$119,666
$122,738

$119,666

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY      
Current liabilities      
Short-term borrowings$1,254
 $714
$1,019
 $714
Long-term debt due within one year2,508
 1,349
4,248
 1,349
Accounts payable3,327
 3,800
3,348
 3,800
Accrued expenses1,725
 2,112
1,877
 2,112
Payables to affiliates5
 5
5
 5
Regulatory liabilities522
 644
400
 644
Mark-to-market derivative liabilities345
 475
239
 475
Unamortized energy contract liabilities151
 149
138
 149
Renewable energy credit obligation348
 344
375
 344
Liabilities held for sale799
 777
11
 777
Other1,245
 1,035
1,425
 1,035
Total current liabilities12,229
 11,404
13,085
 11,404
Long-term debt32,960
 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 credits11,642
 11,330
12,133
 11,330
Asset retirement obligations9,967
 9,679
10,089
 9,679
Pension obligations3,734
 3,988
3,712
 3,988
Non-pension postretirement benefit obligations1,984
 1,928
2,029
 1,928
Spent nuclear fuel obligation1,178
 1,171
1,193
 1,171
Regulatory liabilities9,781
 9,559
9,792
 9,559
Mark-to-market derivative liabilities434
 479
416
 479
Unamortized energy contract liabilities432
 463
368
 463
Other3,158
 2,130
3,123
 2,130
Total deferred credits and other liabilities42,310
 40,727
42,855
 40,727
Total liabilities(a)
87,889

86,596
88,386

86,596
Commitments and contingencies
 

 

Shareholders’ equity      
Common stock (No par value, 2,000 shares authorized, 971 shares and 968 shares outstanding at March 31, 2019 and December 31, 2018, respectively)19,171
 19,116
Treasury stock, at cost (2 shares at March 31, 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 earnings15,321
 14,766
15,871
 14,766
Accumulated other comprehensive loss, net(3,012) (2,995)(2,963) (2,995)
Total shareholders’ equity31,357

30,764
32,023

30,764
Noncontrolling interests2,347
 2,306
2,329
 2,306
Total equity33,704

33,070
34,352

33,070
Total liabilities and shareholders’ equity$121,593

$119,666
$122,738

$119,666
__________
(a)Exelon’s consolidated assets include $9,546$9,465 million and $9,667 million at March 31,September 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 $3,572$3,517 million and $3,548 million at March 31,September 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)
Three Months Ended March 31, 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 income, net of income taxes—
 —
 —
 —
 (17) (1) (18)
Other comprehensive loss, net of income taxes—
 —
 —
 —
 (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
Long-term incentive plan activity320
 14
 —
 —
 —
 —
 14
Employee stock purchase plan issuances311
 24
 —
 —
 —
 —
 24
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 3
 3
Common stock dividends
($0.36/common share)		—
 —
 —
 (353) —
 —
 (353)
Other comprehensive income (loss), net of income taxes—
 —
 —
 —
 22
 (1) 21
Balance, June 30, 2019973,417
 $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

Three Months Ended March 31, 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
Long-term incentive plan activity183
 20
 —
 —
 —
 —
 20
Employee stock purchase plan issuances342
 15
 —
 —
 —
 —
 15
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 (14) (14)
Common stock dividends
($0.35/common share)		—
 —
 —
 (334) —
 —
 (334)
Other comprehensive income, net of income taxes—
 —
 —
 —
 44
 1
 45
Balance, June 30, 2018967,739
 $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
March 31,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2019 20182019 2018 2019 2018
Operating revenues          
Operating revenues$4,979
 $5,114
$4,499
 $4,970
 $13,436
 $14,389
Operating revenues from affiliates317
 398
275
 308
 844
 979
Total operating revenues5,296

5,512
4,774

5,278

14,280

15,368
Operating expenses          
Purchased power and fuel3,204
 3,289
2,648
 2,977
 8,141
 8,542
Purchased power and fuel from affiliates1
 4
3
 3
 7
 10
Operating and maintenance1,068
 1,178
947
 1,218
 3,131
 3,643
Operating and maintenance from affiliates150
 161
140
 152
 439
 483
Depreciation and amortization405
 448
407
 468
 1,221
 1,383
Taxes other than income135
 138
129
 143
 394
 414
Total operating expenses4,963

5,218
4,274

4,961

13,333

14,475
Gain on sales of assets and businesses—
 53
(Loss) gain on sales of assets and businesses(18) (6) 15
 48
Operating income333

347
482

311

962

941
Other income and (deductions)          
Interest expense, net(102) (91)(101) (93) (310) (278)
Interest expense to affiliates(9) (10)(8) (8) (26) (27)
Other, net430
 (44)128
 179
 729
 164
Total other income and (deductions)319

(145)19

78

393

(141)
Income before income taxes652
 202
501
 389
 1,355
 800
Income taxes224
 9
87
 78
 388
 110
Equity in losses of unconsolidated affiliates(6) (7)(170) (11) (183) (23)
Net income422

186
244

300

784

667
Net income attributable to noncontrolling interests59
 50
Net (loss) income attributable to noncontrolling interests(13) 66
 56
 120
Net income attributable to membership interest$363

$136
$257

$234

$728

$547
Comprehensive income, net of income taxes          
Net income$422
 $186
$244
 $300
 $784
 $667
Other comprehensive income (loss), net of income taxes          
Unrealized gain on cash flow hedges1
 7
—
 —
 —
 12
Unrealized (loss) gain on investments in unconsolidated affiliates(2) 1
Unrealized gain (loss) on foreign currency translation2
 (1)
Unrealized gain on investments in unconsolidated affiliates5
 —
 1
 3
Unrealized (loss) gain on foreign currency translation(2) 2
 2
 (4)
Other comprehensive income1

7
3

2

3

11
Comprehensive income423

193
247

302

787

678
Comprehensive income attributable to noncontrolling interests58
 51
Comprehensive (loss) income attributable to noncontrolling interests(10) 66
 57
 122
Comprehensive income attributable to membership interest$365
 $142
$257
 $236
 $730
 $556

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities      
Net income$422
 $186
$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 amortization789
 858
2,377
 2,608
Impairment of long-lived assets7
 —
Asset impairments174
 49
Gain on sales of assets and businesses—
 (53)(15) (48)
Deferred income taxes and amortization of investment tax credits108
 (68)201
 (278)
Net fair value changes related to derivatives33
 264
102
 73
Net realized and unrealized (gains) losses on NDT funds(308) 68
Net realized and unrealized gains on NDT funds(467) (21)
Other non-cash operating activities(90) 45
(95) 187
Changes in assets and liabilities:
 

 
Accounts receivable197
 194
395
 126
Receivables from and payables to affiliates, net(5) (15)(12) (7)
Inventories103
 122
(36) (10)
Accounts payable and accrued expenses(411) (317)(428) (59)
Option premiums received (paid), net6
 (27)13
 (36)
Collateral posted, net(87) (214)
Collateral (posted) received, net(292) 228
Income taxes146
 79
327
 220
Pension and non-pension postretirement benefit contributions(141) (125)(165) (134)
Other assets and liabilities(187) (142)(390) (154)
Net cash flows provided by operating activities582

855
2,473

3,411
Cash flows from investing activities      
Capital expenditures(511) (628)(1,282) (1,660)
Proceeds from NDT fund sales3,713
 1,189
8,443
 6,379
Investment in NDT funds(3,666) (1,248)(8,437) (6,553)
Acquisition of assets and businesses, net—
 (57)
Proceeds from sales of assets and businesses8
 79
17
 90
Other investing activities23
 (7)(6) (5)
Net cash flows used in investing activities(433)
(615)(1,265)
(1,806)
Cash flows from financing activities      
Changes in short-term borrowings—
 165
Proceeds from short-term borrowings with maturities greater than 90 days—
 1
Repayments of short-term borrowings with maturities greater than 90 days—
 (1)
Issuance of long-term debt2
 4
41
 14
Retirement of long-term debt(47) (29)(196) (100)
Changes in Exelon intercompany money pool(100) —
(100) (54)
Distributions to member(225) (188)(674) (688)
Contributions from member—

54
Other financing activities(6) (9)(37) (46)
Net cash flows used in financing activities(376)
(57)(966)
(820)
(Decrease) increase in cash, cash equivalents and restricted cash(227) 183
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$676

$737
$1,145

$1,339
   
Supplemental cash flow information   
Decrease in capital expenditures not paid$(24) $(226)
Increase in PPE related to ARO update342
 47

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$537
 $750
$1,019
 $750
Restricted cash and cash equivalents139
 153
126
 153
Accounts receivable, net      
Customer2,800
 2,941
Other367
 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 assets652
 804
602
 804
Receivables from affiliates163
 173
166
 173
Unamortized energy contract assets49
 49
49
 49
Inventories, net      
Fossil fuel and emission allowances146
 251
243
 251
Materials and supplies965
 963
1,010
 963
Assets held for sale890
 904
18
 904
Other1,013
 883
1,002
 883
Total current assets7,721

8,433
7,159

8,433
Property, plant and equipment, net24,034
 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 funds12,302
 11,661
12,706
 11,661
Investments404
 414
248
 414
Goodwill47
 47
47
 47
Mark-to-market derivative assets454
 452
483
 452
Prepaid pension asset1,525
 1,421
1,472
 1,421
Unamortized energy contract assets364
 371
352
 371
Deferred income taxes18
 21
11
 21
Other1,813
 755
1,915
 755
Total deferred debits and other assets16,927

15,142
17,234

15,142
Total assets(a)
$48,682

$47,556
$47,984

$47,556

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND EQUITY      
Current liabilities      
Long-term debt due within one year$2,365
 $906
$2,706
 $906
Accounts payable1,566
 1,847
1,583
 1,847
Accrued expenses675
 898
762
 898
Payables to affiliates136
 139
134
 139
Borrowings from Exelon intercompany money pool—
 100
—
 100
Mark-to-market derivative liabilities318
 449
212
 449
Unamortized energy contract liabilities28
 31
21
 31
Renewable energy credit obligation348
 343
374
 343
Liabilities held for sale799
 777
11
 777
Other425
 279
541
 279
Total current liabilities6,660
 5,769
6,344
 5,769
Long-term debt5,487
 6,989
5,018
 6,989
Long-term debt to affiliates895
 898
889
 898
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits3,502
 3,383
3,607
 3,383
Asset retirement obligations9,737
 9,450
9,855
 9,450
Non-pension postretirement benefit obligations894
 900
885
 900
Spent nuclear fuel obligation1,178
 1,171
1,193
 1,171
Payables to affiliates2,870
 2,606
2,960
 2,606
Mark-to-market derivative liabilities219
 252
163
 252
Unamortized energy contract liabilities16
 20
11
 20
Other1,528
 610
1,466
 610
Total deferred credits and other liabilities19,944
 18,392
20,140
 18,392
Total liabilities(a)
32,986
 32,048
32,391
 32,048
Commitments and contingencies
 

 

Equity      
Member’s equity      
Membership interest9,525
 9,518
9,525
 9,518
Undistributed earnings3,862
 3,724
3,778
 3,724
Accumulated other comprehensive loss, net(36) (38)(36) (38)
Total member’s equity13,351
 13,204
13,267
 13,204
Noncontrolling interests2,345
 2,304
2,326
 2,304
Total equity15,696
 15,508
15,593
 15,508
Total liabilities and equity$48,682
 $47,556
$47,984
 $47,556
__________
(a)Generation’s consolidated assets include $9,515$9,443 million and $9,634 million at March 31,September 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 $3,508$3,467 million and $3,480 million at March 31,September 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)
Three Months Ended March 31, 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
Changes in equity of noncontrolling interests—
 —
 —
 3
 3
Distributions to member—
 (224) —
 —
 (224)
Other comprehensive loss, net of income taxes—
 —
 —
 (1) (1)
Balance, June 30, 2019$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


Three Months Ended March 31, 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
Changes in equity of noncontrolling interests—
 —
 —
 (13) (13)
Distributions to member—
 (189) —
 —
 (189)
Other comprehensive income, net of income taxes—
 —
 1
 1
 2
Balance, June 30, 2018$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
March 31,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2019 20182019 2018 2019 2018
Operating revenues          
Electric operating revenues$1,432
 $1,493
$1,635
 $1,609
 $4,427
 $4,512
Revenues from alternative revenue programs(28) 5
(56) (15) (98) (27)
Operating revenues from affiliates4
 14
4
 4
 13
 23
Total operating revenues1,408

1,512
1,583

1,598

4,342

4,508
Operating expenses          
Purchased power388
 411
494
 496
 1,199
 1,281
Purchased power from affiliate97
 194
83
 123
 270
 421
Operating and maintenance259
 253
267
 276
 771
 785
Operating and maintenance from affiliate62
 60
73
 61
 196
 189
Depreciation and amortization251
 228
259
 237
 767
 696
Taxes other than income78
 77
80
 82
 228
 238
Total operating expenses1,135

1,223
1,256

1,275

3,431

3,610
Gain on sales of assets3
 3
1
 —
 4
 5
Operating income276

292
328

323

915

903
Other income and (deductions)          
Interest expense, net(84) (86)(87) (82) (258) (251)
Interest expense to affiliates(3) (3)(4) (3) (10) (10)
Other, net8
 8
8
 7
 27
 21
Total other income and (deductions)(79)
(81)(83)
(78)
(241)
(240)
Income before income taxes197
 211
245
 245
 674
 663
Income taxes40
 46
45
 52
 130
 140
Net income$157

$165
$200

$193

$544

$523
Comprehensive income$157
 $165
$200
 $193
 $544
 $523

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities      
Net income$157
 $165
$544
 $523
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization251
 228
767
 696
Deferred income taxes and amortization of investment tax credits34
 50
115
 214
Other non-cash operating activities56
 46
180
 187
Changes in assets and liabilities:      
Accounts receivable14
 39
(38) (190)
Receivables from and payables to affiliates, net(34) (19)(27) 8
Inventories(3) 5
(16) 4
Accounts payable and accrued expenses(188) (158)(132) (38)
Collateral posted, net(13) (3)43
 (10)
Income taxes5
 (5)25
 (65)
Pension and non-pension postretirement benefit contributions(67) (38)(71) (41)
Other assets and liabilities(121) (176)(245) (170)
Net cash flows provided by operating activities91

134
1,145

1,118
Cash flows from investing activities      
Capital expenditures(503) (531)(1,413) (1,540)
Other investing activities11
 8
25
 22
Net cash flows used in investing activities(492)
(523)(1,388)
(1,518)
Cash flows from financing activities      
Changes in short-term borrowings322
 317
387
 —
Issuance of long-term debt400
 800
400
 1,350
Retirement of long-term debt(300) (700)(300) (840)
Contributions from parent63
 113
187
 387
Dividends paid on common stock(127) (114)(380) (345)
Other financing activities(9) (9)(10) (16)
Net cash flows provided by financing activities349

407
284

536
(Decrease) increase in cash, cash equivalents and restricted cash(52) 18
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$278

$162
$371

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

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$68
 $135
$76
 $135
Restricted cash17
 29
124
 29
Accounts receivable, net      
Customer539
 539
Other336
 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 affiliates21
 20
27
 20
Inventories, net152
 148
162
 148
Regulatory assets285
 293
286
 293
Other89
 86
48
 86
Total current assets1,507

1,570
1,606

1,570
Property, plant and equipment, net22,274
 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 assets1,338
 1,307
1,436
 1,307
Investments6
 6
6
 6
Goodwill2,625
 2,625
2,625
 2,625
Receivables from affiliates2,412
 2,217
2,487
 2,217
Prepaid pension asset1,073
 1,035
1,020
 1,035
Other347
 395
351
 395
Total deferred debits and other assets7,801

7,585
7,925

7,585
Total assets$31,582

$31,213
$32,326

$31,213

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY      
Current liabilities      
Short-term borrowings$322
 $—
$387
 $—
Long-term debt due within one year—
 300
500
 300
Accounts payable491
 607
520
 607
Accrued expenses229
 373
275
 373
Payables to affiliates74
 119
87
 119
Customer deposits112
 111
116
 111
Regulatory liabilities241
 293
193
 293
Mark-to-market derivative liability27
 26
27
 26
Other98
 96
138
 96
Total current liabilities1,594
 1,925
2,243
 1,925
Long-term debt8,194
 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 credits3,870
 3,813
4,016
 3,813
Asset retirement obligations119
 118
120
 118
Non-pension postretirement benefits obligations196
 201
185
 201
Regulatory liabilities6,269
 6,050
6,390
 6,050
Mark-to-market derivative liability213
 223
253
 223
Other582
 630
621
 630
Total deferred credits and other liabilities11,249
 11,035
11,585
 11,035
Total liabilities21,242
 20,966
21,729
 20,966
Commitments and contingencies
 

 

Shareholders’ equity      
Common stock1,588
 1,588
1,588
 1,588
Other paid-in capital7,385
 7,322
7,509
 7,322
Retained deficit unappropriated(1,639) (1,639)(1,639) (1,639)
Retained earnings appropriated3,006
 2,976
3,139
 2,976
Total shareholders’ equity10,340
 10,247
10,597
 10,247
Total liabilities and shareholders’ equity$31,582
 $31,213
$32,326
 $31,213

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Three Months Ended March 31, 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, 2019$1,588

$7,385

$(1,639)
$3,006

$10,340
$1,588
 $7,385
 $(1,639) $3,006
 $10,340
         
Net income—
 —
 186
 —
 186
Appropriation of retained earnings for future dividends—
 —
 (186) 186
 —
Common stock dividends—
 —
 —
 (127) (127)
Contributions from parent—
 61
 —
 —
 61
Balance, June 30, 2019$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
                  
Three Months Ended March 31, 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, 2018$1,588
 $6,935
 $(1,639) $2,822
 $9,706
$1,588
 $6,935
 $(1,639) $2,822
 $9,706
Net income—
 —
 164
 —
 164
Appropriation of retained earnings for future dividends—
 —
 (164) 164
 —
Common stock dividends—
 —
 —
 (115) (115)
Contributions from parent—
 112
 —
 —
 112
Balance, June 30, 2018$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
March 31,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2019 20182019 2018 2019 2018
Operating revenues          
Electric operating revenues$622
 $633
$726
 $697
 $1,914
 $1,886
Natural gas operating revenues280
 232
62
 57
 431
 382
Revenues from alternative revenue programs(3) (1)(11) 1
 (16) 2
Operating revenues from affiliates1
 2
1
 2
 4
 5
Total operating revenues900

866
778

757

2,333

2,275
Operating expenses          
Purchased power152
 199
185
 215
 461
 576
Purchased fuel135
 98
18
 14
 184
 148
Purchased power from affiliate44
 36
43
 34
 122
 94
Operating and maintenance187
 233
182
 184
 531
 572
Operating and maintenance from affiliates38
 42
37
 35
 112
 114
Depreciation and amortization81
 75
83
 75
 247
 224
Taxes other than income41
 41
47
 46
 126
 125
Total operating expenses678

724
595

603

1,783

1,853
Gain on sales of assets—
 —
 —
 1
Operating income222

142
183

154

550

423
Other income and (deductions)          
Interest expense, net(30) (30)(30) (28) (91) (85)
Interest expense to affiliates(3) (3)(3) (4) (9) (11)
Other, net4
 2
4
 2
 11
 4
Total other income and (deductions)(29)
(31)(29)
(30)
(89)
(92)
Income before income taxes193

111
154
 124
 461

331
Income taxes25
 (2)14
 (2) 51
 (5)
Net income$168

$113
$140

$126

$410

$336
Comprehensive income$168
 $113
$140
 $126
 $410
 $336

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities      
Net income$168
 $113
$410
 $336
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization81
 75
247
 224
Gain on sales of assets—
 (1)
Deferred income taxes and amortization of investment tax credits5
 (4)6
 5
Other non-cash operating activities16
 21
28
 41
Changes in assets and liabilities:      
Accounts receivable(86) (51)46
 (85)
Receivables from and payables to affiliates, net7
 7
(12) 1
Inventories23
 12
(3) (13)
Accounts payable and accrued expenses(13) 6
(32) (1)
Income taxes20
 5
(15) (16)
Pension and non-pension postretirement benefit contributions(25) (24)(26) (25)
Other assets and liabilities(119) (141)(111) 26
Net cash flows provided by operating activities77

19
538

492
Cash flows from investing activities      
Capital expenditures(222) (217)(675) (615)
Other investing activities2
 2
7
 6
Net cash flows used in investing activities(220)
(215)(668)
(609)
Cash flows from financing activities      
Changes in short-term borrowings—
 220
Issuance of long-term debt—
 325
325
 700
Retirement of long-term debt—
 (500)—
 (500)
Changes in Exelon intercompany money pool—
 194
Contributions from parent145
 —
174
 71
Dividends paid on common stock(90) (287)(268) (300)
Other financing activities—
 (5)(6) (22)
Net cash flows provided by (used in) financing activities55

(53)225

(51)
Decrease in cash, cash equivalents and restricted cash(88) (249)
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$47

$26
$230

$107
   
Supplemental cash flow information   
Increase in capital expenditures not paid$42
 $4

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$41
 $130
$224
 $130
Restricted cash and cash equivalents6
 5
6
 5
Accounts receivable, net      
Customer394
 321
Other148
 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 fuel15
 38
41
 38
Materials and supplies37
 37
37
 37
Prepaid utility taxes100
 —
34
 —
Regulatory assets54
 81
63
 81
Other21
 19
27
 19
Total current assets816

782
843

782
Property, plant and equipment, net8,766
 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 assets491
 460
540
 460
Investments25
 25
26
 25
Receivable from affiliates457
 389
473
 389
Prepaid pension asset372
 349
367
 349
Other29
 27
30
 27
Total deferred debits and other assets1,374

1,250
1,436

1,250
Total assets$10,956

$10,642
$11,379

$10,642

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Accounts payable379
 370
382
 370
Accrued expenses119
 113
97
 113
Payables to affiliates66
 59
54
 59
Customer deposits68
 68
69
 68
Regulatory liabilities123
 175
93
 175
Other32
 24
27
 24
Total current liabilities787
 809
722
 809
Long-term debt3,084
 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 credits1,974
 1,933
2,034
 1,933
Asset retirement obligations27
 27
28
 27
Non-pension postretirement benefits obligations288
 288
289
 288
Regulatory liabilities488
 421
503
 421
Other81
 76
79
 76
Total deferred credits and other liabilities2,858
 2,745
2,933
 2,745
Total liabilities6,913
 6,822
7,243
 6,822
Commitments and contingencies
 

 

Shareholder’s equity      
Common stock2,723
 2,578
2,752
 2,578
Retained earnings1,320
 1,242
1,384
 1,242
Total shareholder’s equity4,043
 3,820
4,136
 3,820
Total liabilities and shareholder's equity$10,956
 $10,642
$11,379
 $10,642

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
 Nine months ended September 30, 2019
(In millions)
Common
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income, net
 
Total
Shareholder's
Equity
Balance, December 31, 2018$2,578
 $1,242
 $—
 $3,820
Net income—
 168
 —
 168
Common stock dividends—
 (90) —
 (90)
Contributions from parent145
 —
 —
 145
Balance, March 31, 2019$2,723
 $1,320
 $—
 $4,043
Net income—
 102
 —
 102
Common stock dividends—
 (90) —
 (90)
Balance, June 30, 2019$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
        
 Nine months ended September 30, 2018
(In millions)Common
Stock		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income, net		 Total
Shareholder's
Equity
Balance, December 31, 2017$2,489
 $1,087
 $1
 $3,577
Net income—
 113
 —
 113
Common stock dividends—
 (287) —
 (287)
Impact of adoption of Recognition and Measurement of Financial Assets and
Liabilities Standard
—
 1
 (1) —
Balance, March 31, 2018$2,489
 $914
 $—
 $3,403
Net income—
 96
 —
 96
Common stock dividends—
 (5) —
 (5)
Contributions from parent41
 —
 —
 41
Balance, June 30, 2018$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
 Three months ended March 31, 2019
(In millions)
Common
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income, net
 
Total
Shareholder's
Equity
Balance, December 31, 2018$2,578
 $1,242
 $—
 $3,820
Net income—
 168
 —
 168
Common stock dividends—
 (90) —
 (90)
Contributions from parent145
 —
 —
 145
Balance, March 31, 2019$2,723
 $1,320
 $—
 $4,043
        
 Three months ended March 31, 2018
(In millions)Common
Stock		 Retained
Earnings		 Accumulated
Other
Comprehensive
Income, net		 Total
Shareholder's
Equity
Balance, December 31, 2017$2,489
 $1,087
 $1
 $3,577
Net income—
 113
 —
 113
Common stock dividends—
 (287) —
 (287)
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities Standard—
 1
 (1) —
Balance, March 31, 2018$2,489
 $914
 $—
 $3,403

BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
March 31,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2019 20182019 2018 2019 2018
Operating revenues          
Electric operating revenues$652
 $654
$623
 $652
 $1,814
 $1,847
Natural gas operating revenues308
 330
79
 79
 484
 527
Revenues from alternative revenue programs10
 (13)(5) (6) 11
 (23)
Operating revenues from affiliates6
 6
6
 6
 18
 18
Total operating revenues976

977
703

731

2,327

2,369
Operating expenses          
Purchased power190
 192
159
 183
 480
 510
Purchased fuel95
 123
12
 21
 128
 176
Purchased power from affiliate75
 65
64
 68
 196
 195
Operating and maintenance153
 184
157
 144
 451
 462
Operating and maintenance from affiliates39
 37
39
 38
 118
 116
Depreciation and amortization136
 134
116
 110
 368
 358
Taxes other than income68
 65
65
 64
 195
 188
Total operating expenses756

800
612

628

1,936

2,005
Gain on sales of assets—
 —
 —
 1
Operating income220

177
91

103

391

365
Other income and (deductions)          
Interest expense, net(29) (25)(31) (27) (89) (78)
Other, net5
 4
7
 5
 18
 14
Total other income and (deductions)(24)
(21)(24)
(22)
(71)
(64)
Income before income taxes196

156
67
 81
 320

301
Income taxes36
 28
12
 18
 59
 59
Net income$160

$128
$55

$63

$261

$242
Comprehensive income$160
 $128
$55
 $63
 $261
 $242

BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities      
Net income$160
 $128
$261
 $242
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization136
 134
368
 358
Deferred income taxes and amortization of investment tax credits28
 22
66
 82
Other non-cash operating activities27
 20
63
 42
Changes in assets and liabilities:      
Accounts receivable(39) (32)110
 72
Receivables from and payables to affiliates, net(10) —
(14) (4)
Inventories17
 20
(5) (8)
Accounts payable and accrued expenses(27) (9)(28) (3)
Collateral posted, net(1) —
Collateral (posted) received, net(5) 1
Income taxes8
 14
(43) (48)
Pension and non-pension postretirement benefit contributions(40) (45)(45) (50)
Other assets and liabilities(14) 61
(65) (9)
Net cash flows provided by operating activities245

313
663

675
Cash flows from investing activities      
Capital expenditures(258) (224)(842) (667)
Other investing activities1
 1
4
 8
Net cash flows used in investing activities(257)
(223)(838)
(659)
Cash flows from financing activities      
Changes in short-term borrowings71
 (32)(35) (77)
Issuance of long-term debt400
 300
Dividends paid on common stock(56) (52)(169) (157)
Net cash flows provided by (used in) financing activities15

(84)
Contributions from parent104
 18
Other financing activities(7) (2)
Net cash flows provided by financing activities293

82
Increase in cash, cash equivalents and restricted cash3
 6
118
 98
Cash, cash equivalents and restricted cash at beginning of period13
 18
13
 18
Cash, cash equivalents and restricted cash at end of period$16

$24
$131

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

BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$12
 $7
$130
 $7
Restricted cash and cash equivalents4
 6
1
 6
Accounts receivable, net      
Customer385
 353
Other89
 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 fuel16
 36
34
 36
Materials and supplies42
 39
46
 39
Prepaid utility taxes38
 74
—
 74
Regulatory assets161
 177
180
 177
Other6
 3
7
 3
Total current assets753

786
751

786
Property, plant and equipment, net8,408
 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 assets395
 398
386
 398
Investments5
 5
7
 5
Prepaid pension asset301
 279
276
 279
Other105
 5
88
 5
Total deferred debits and other assets806

687
757

687
Total assets$9,967

$9,716
$10,304

$9,716

BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Short-term borrowings$—
 $35
Accounts payable245
 295
Accrued expenses165
 155
Payables to affiliates51
 65
Customer deposits120
 120
Regulatory liabilities21
 77
Other63
 27
Total current liabilities665
 774
Long-term debt3,270
 2,876
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits1,329
 1,222
Asset retirement obligations22
 24
Non-pension postretirement benefits obligations198
 201
Regulatory liabilities1,158
 1,192
Other112
 73
Total deferred credits and other liabilities2,819
 2,712
Total liabilities6,754
 6,362
Commitments and contingencies

 

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

(In millions)March 31, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY   
Current liabilities   
Short-term borrowings$106
 $35
Accounts payable291
 295
Accrued expenses142
 155
Payables to affiliates54
 65
Customer deposits120
 120
Regulatory liabilities67
 77
Other54
 27
Total current liabilities834
 774
Long-term debt2,876
 2,876
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits1,275
 1,222
Asset retirement obligations24
 24
Non-pension postretirement benefits obligations198
 201
Regulatory liabilities1,172
 1,192
Other130
 73
Total deferred credits and other liabilities2,799
 2,712
Total liabilities6,509
 6,362
Commitments and contingencies
 
Shareholders’ equity   
Common stock1,714
 1,714
Retained earnings1,744
 1,640
Total shareholders' equity3,458
 3,354
Total liabilities and shareholders’ equity$9,967
 $9,716



BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Three Months Ended March 31, 2019Nine Months Ended September 30, 2019
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholders’
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
Common stock dividends—
 (55) (55)
Balance, June 30, 2019$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
          
Three Months Ended March 31, 2018Nine Months Ended September 30, 2018
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholders’
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
Common stock dividends—
 (53) (53)
Balance, June 30, 2018$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
March 31,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2019 20182019 2018 2019 2018
Operating revenues          
Electric operating revenues$1,139
 $1,151
$1,365
 $1,340
 $3,570
 $3,541
Natural gas operating revenues71
 78
20
 23
 115
 129
Revenues from alternative revenue programs15
 18
(9) (5) 4
 7
Operating revenues from affiliates3
 4
4
 3
 11
 11
Total operating revenues1,228
 1,251
1,380
 1,361
 3,700
 3,688
Operating expenses          
Purchased power355
 374
428
 415
 1,086
 1,077
Purchased fuel34
 41
8
 12
 51
 65
Purchased power and fuel from affiliates101
 105
83
 82
 254
 268
Operating and maintenance239
 271
254
 261
 706
 751
Operating and maintenance from affiliates33
 38
36
 31
 105
 106
Depreciation, amortization and accretion180
 183
Depreciation and amortization193
 192
 562
 555
Taxes other than income111
 113
122
 123
 342
 343
Total operating expenses1,053
 1,125
1,124
 1,116
 3,106
 3,165
Operating income175
 126
256
 245

594
 523
Other income and (deductions)          
Interest expense, net(65) (63)(66) (65) (197) (193)
Other, net12
 11
13
 11
 39
 33
Total other income and (deductions)(53) (52)(53) (54) (158) (160)
Income before income taxes122
 74
203
 191
 436
 363
Income taxes5
 9
14
 4
 25
 28
Equity in earnings of unconsolidated affiliate—
 —
 1
 1
Net income$117
 $65
$189
 $187
 $412
 $336
Comprehensive income$117
 $65
$189
 $187
 $412
 $336

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities  
  
Net income$117
 $65
$412
 $336
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization180
 183
562
 555
Deferred income taxes and amortization of investment tax credits—
 17
8
 50
Other non-cash operating activities35
 53
122
 109
Changes in assets and liabilities:      
Accounts receivable(11) (9)(64) (89)
Receivables from and payables to affiliates, net(8) 10
1
 10
Inventories(12) 4
(36) —
Accounts payable and accrued expenses(9) 44
—
 115
Income taxes4
 (9)(11) (31)
Pension and non-pension postretirement benefit contributions(6) (55)(15) (66)
Other assets and liabilities(61) (24)(102) (144)
Net cash flows provided by operating activities229
 279
877
 845
Cash flows from investing activities      
Capital expenditures(358) (258)(1,006) (988)
Other investing activities1
 —
3
 2
Net cash flows used in investing activities(357)
(258)(1,003)
(986)
Cash flows from financing activities      
Changes in short-term borrowings147
 57
78
 (141)
Proceeds from short-term borrowings with maturities greater than 90 days—
 125
Repayments of short-term borrowings with maturities greater than 90 days(125) —
Issuance of long-term debt410
 300
Retirement of long-term debt(5) (12)(130) (33)
Change in Exelon intercompany money pool10
 10
Distributions to member(128) (71)(429) (232)
Contributions from member19
 —
283
 237
Change in Exelon intercompany money pool—
 13
Net cash flows provided by (used in) financing activities33
 (13)
Other financing activities(5) (6)
Net cash flows provided by financing activities92
 260
(Decrease) increase in cash, cash equivalents and restricted cash(95) 8
(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$91
 $103
$152
 $214
   
Supplemental cash flow information   
(Decrease) increase in capital expenditures not paid$(62) $54

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$33
 $124
$99
 $124
Restricted cash and cash equivalents39
 43
38
 43
Accounts receivable, net      
Customer445
 453
Other189
 177
Receivable from affiliates1
 —
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 Fuel2
 9
8
 9
Materials and supplies184
 163
203
 163
Regulatory assets506
 489
479
 489
Other54
 75
50
 75
Total current assets1,453

1,533
1,578

1,533
Property, plant and equipment, net13,619
 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 assets2,236
 2,312
2,095
 2,312
Investments132
 130
135
 130
Goodwill4,005
 4,005
4,005
 4,005
Prepaid pension asset467
 486
426
 486
Deferred income taxes12
 12
13
 12
Other370
 60
356
 60
Total deferred debits and other assets7,222

7,005
7,030

7,005
Total assets(a)
$22,294

$21,984
$22,576

$21,984

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND MEMBER'S EQUITY      
Current liabilities      
Short-term borrowings$326
 $179
$132
 $179
Long-term debt due within one year125
 125
118
 125
Accounts payable441
 496
416
 496
Accrued expenses253
 256
279
 256
Payables to affiliates87
 94
95
 94
Borrowings from Exelon intercompany money pool10
 —
Customer deposits118
 116
Regulatory liabilities76
 84
78
 84
Unamortized energy contract liabilities123
 119
117
 119
Customer deposits117
 116
Other127
 123
152
 123
Total current liabilities1,675
 1,592
1,515
 1,592
Long-term debt6,119
 6,134
6,376
 6,134
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits2,182
 2,146
2,289
 2,146
Asset retirement obligations52
 52
57
 52
Non-pension postretirement benefit obligations101
 103
99
 103
Regulatory liabilities1,829
 1,864
1,725
 1,864
Unamortized energy contract liabilities416
 442
357
 442
Other630
 369
610
 369
Total deferred credits and other liabilities5,210
 4,976
5,137
 4,976
Total liabilities(a)
13,004
 12,702
13,028
 12,702
Commitments and contingencies
 

 

Member's equity      
Membership interest9,239
 9,220
9,503
 9,220
Undistributed earnings51
 62
45
 62
Total member's equity9,290

9,282
9,548

9,282
Total liabilities and member's equity$22,294

$21,984
$22,576

$21,984
__________
(a)PHI’s consolidated total assets include $31$22 million and $33 million at March 31,September 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 $64$50 million and $69 million at March 31,September 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)
Three Months Ended March 31, 2019Nine Months Ended September 30, 2019
(In millions)Membership Interest Undistributed Earnings (Losses) Member's EquityMembership Interest Undistributed Earnings (Losses) Member's Equity
Balance, December 31, 2018$9,220
 $62
 $9,282
$9,220
 $62
 $9,282
Net income—
 117
 117
—
 117
 117
Distributions to member—
 (128) (128)—
 (128) (128)
Contributions from member19
 —
 19
19
 —
 19
Balance, March 31, 2019$9,239
 $51
 $9,290
$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
 Three Months Ended March 31, 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



 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 March 31,Three Months Ended
September 30,
Nine Months Ended
September 30,
(In millions)2019
20182019
2018
2019
2018
Operating revenues          
Electric operating revenues$559
 $536
$643
 $630
 $1,733
 $1,697
Revenues from alternative revenue programs14
 19
(3) (4) 10
 6
Operating revenues from affiliates2
 2
2
 2
 5
 5
Total operating revenues575
 557
642
 628
 1,748
 1,708
Operating expenses          
Purchased power117
 130
116
 131
 325
 354
Purchased power from affiliates70
 52
65
 46
 188
 143
Operating and maintenance64
 73
85
 84
 208
 216
Operating and maintenance from affiliates54
 57
50
 52
 156
 167
Depreciation and amortization94
 96
95
 99
 281
 286
Taxes other than income92
 93
104
 104
 286
 288
Total operating expenses491
 501
515
 516
 1,444
 1,454
Operating income84
 56
127
 112
 304
 254
Other income and (deductions)          
Interest expense, net(34) (31)(33) (32) (100) (96)
Other, net7
 8
9
 7
 22
 23
Total other income and (deductions)(27) (23)(24) (25) (78) (73)
Income before income taxes57
 33
103
 87
 226
 181
Income taxes2
 2
5
 (2) 9
 7
Net income$55
 $31
$98
 $89
 $217
 $174
Comprehensive income$55
 $31
$98
 $89
 $217
 $174

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,		Nine Months Ended
September 30,
(In millions)2019 20182019 2018
Cash flows from operating activities      
Net income$55
 $31
$217
 $174
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization94
 96
281
 286
Deferred income taxes and amortization of investment tax credits(2) 4
12
 (5)
Other non-cash operating activities3
 10
43
 42
Changes in assets and liabilities:      
Accounts receivable(19) —
(49) (36)
Receivables from and payables to affiliates, net3
 (18)4
 (9)
Inventories(14) (2)(23) 6
Accounts payable and accrued expenses(2) 36
(12) 104
Income taxes4
 (3)(23) (18)
Pension and non-pension postretirement benefit contributions(4) (7)(10) (11)
Other assets and liabilities(37) (21)(55) (137)
Net cash flows provided by operating activities81
 126
385
 396
Cash flows from investing activities      
Capital expenditures(144) (127)(455) (475)
Other investing activities1
 —
2
 3
Net cash flows used in investing activities(143) (127)(453) (472)
Cash flows from financing activities      
Changes in short-term borrowings65
 34
(28) 38
Issuance of long-term debt260
 100
Retirement of long-term debt(118) (8)
Dividends paid on common stock(24) (25)(173) (128)
Contributions from parent14
 —
129
 85
Other financing activities(3) (4)
Net cash flows provided by financing activities55
 9
67
 83
(Decrease) increase in cash, cash equivalents and restricted cash(7) 8
(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$46
 $48
$52
 $47
   
Supplemental cash flow information   
(Decrease) increase in capital expenditures not paid$(7) $15

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019
December 31, 2018September 30, 2019
December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$11
 $16
$18
 $16
Restricted cash and cash equivalents35
 37
34
 37
Accounts receivable, net      
Customer219
 225
Other102
 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 affiliates1
 1
—
 1
Inventories, net109
 93
118
 93
Regulatory assets270
 270
252
 270
Other22
 37
12
 37
Total current assets769

760
806

760
Property, plant and equipment, net6,534
 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 assets620
 643
577
 643
Investments106
 105
109
 105
Prepaid pension asset311
 316
301
 316
Other80
 15
76
 15
Total deferred debits and other assets1,117

1,079
1,063

1,079
Total assets$8,420

$8,299
$8,603

$8,299

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Short-term borrowings$105
 $40
$12
 $40
Long-term debt due within one year15
 15
8
 15
Accounts payable188
 214
177
 214
Accrued expenses139
 126
144
 126
Payables to affiliates65
 62
65
 62
Customer deposits55
 54
56
 54
Regulatory liabilities6
 7
9
 7
Merger related obligation38
 38
38
 38
Current portion of DC PLUG obligation30
 30
30
 30
Other17
 42
25
 42
Total current liabilities658

628
564

628
Long-term debt2,705
 2,704
2,852
 2,704
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits1,081
 1,064
1,150
 1,064
Asset retirement obligations41
 37
Non-pension postretirement benefit obligations26
 29
23
 29
Regulatory liabilities805
 822
749
 822
Other360
 312
311
 275
Total deferred credits and other liabilities2,272

2,227
2,274

2,227
Total liabilities5,635

5,559
5,690

5,559
Commitments and contingencies
 

 

Shareholder's equity      
Common stock1,650
 1,636
1,765
 1,636
Retained earnings1,135
 1,104
1,148
 1,104
Total shareholder's equity2,785
 2,740
2,913
 2,740
Total liabilities and shareholder's equity$8,420
 $8,299
$8,603
 $8,299

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Three Months Ended March 31, 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, 2019$1,650

$1,135

$2,785
$1,650
 $1,135
 $2,785
     
Three Months Ended March 31, 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
—
 64
 64
Common stock dividends—
 (25) (25)—
 (48) (48)
Balance, March 31, 2018$1,470
 $1,069
 $2,539
Contributions from parent115
 —
 115
Balance, June 30, 2019$1,765
 $1,151
 $2,916
Net income—
 98
 98
Common stock dividends—
 (101) (101)
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 March 31,Three Months Ended
September 30,
Nine Months Ended
September 30,
(In millions)2019
20182019
2018
2019
2018
Operating revenues          
Electric operating revenues$307
 $303
$304
 $302
 $872
 $861
Natural gas operating revenues71
 78
20
 24
 116
 129
Revenues from alternative revenue programs—
 1
(6) —
 (6) 5
Operating revenues from affiliates2
 2
1
 2
 5
 6
Total operating revenues380

384
319

328

987

1,001
Operating expenses          
Purchased power107
 90
105
 96
 298
 258
Purchased fuel34
 41
8
 11
 51
 64
Purchased power from affiliate23
 46
14
 26
 50
 103
Operating and maintenance45
 57
43
 44
 127
 137
Operating and maintenance from affiliates39
 41
37
 38
 113
 119
Depreciation and amortization46
 45
46
 47
 138
 135
Taxes other than income14
 15
15
 15
 43
 43
Total operating expenses308

335
268

277

820

859
Operating income72

49
51

51

167

142
Other income and (deductions)          
Interest expense, net(15) (13)(15) (15) (45) (42)
Other, net3
 2
2
 2
 10
 7
Total other income and (deductions)(12)
(11)(13)
(13)
(35)
(35)
Income before income taxes60
 38
38
 38
 132
 107
Income taxes7
 7
5
 5
 16
 17
Net income$53

$31
$33

$33

$116

$90
Comprehensive income$53
 $31
$33
 $33
 $116
 $90

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,		Nine Months Ended
September 30,
(In millions)2019
20182019
2018
Cash flows from operating activities      
Net income$53
 $31
$116
 $90
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization46
 45
138
 135
Deferred income taxes and amortization of investment tax credits1
 10
(2) 24
Other non-cash operating activities11
 19
21
 16
Changes in assets and liabilities:      
Accounts receivable(5) (1)29
 13
Receivables from and payables to affiliates, net(15) (16)(7) (14)
Inventories1
 7
(7) (3)
Accounts payable and accrued expenses11
 18
3
 18
Income taxes5
 (5)11
 —
Pension and non-pension postretirement benefit contributions(1) —
Other assets and liabilities(10) 7
(22) 13
Net cash flows provided by operating activities98

115
279

292
Cash flows from investing activities      
Capital expenditures(78) (65)(245) (254)
Other investing activities1
 1
Net cash flows used in investing activities(78)
(65)(244)
(253)
Cash flows from financing activities      
Changes in short-term borrowings5
 (5)57
 (216)
Issuance of long-term debt—
 200
Retirement of long-term debt—
 (4)—
 (4)
Dividends paid on common stock(41) (36)(105) (58)
Net cash flows used in financing activities(36)
(45)
Contributions from parent—
 150
Other financing activities—
 (3)
Net cash flows (used in) provided by financing activities(48)
69
(Decrease) increase in cash, cash equivalents and restricted cash(16) 5
(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$8

$7
$11

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

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$7
 $23
$11
 $23
Restricted cash and cash equivalents1
 1
—
 1
Accounts receivable, net      
Customer141
 134
Other39
 46
Receivables from affiliates2
 —
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 Fuel2
 9
8
 9
Materials and supplies43
 37
47
 37
Prepaid utility taxes15
 17
Regulatory assets60
 59
62
 59
Other21
 27
5
 10
Total current assets316

336
297

336
Property, plant and equipment, net3,848
 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 assets225
 231
221
 231
Goodwill8
 8
8
 8
Prepaid pension asset182
 186
175
 186
Other81
 6
82
 6
Total deferred debits and other assets496

431
486

431
Total assets$4,660

$4,588
$4,724

$4,588

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Short-term borrowings$5
 $—
$57
 $—
Long-term debt due within one year91
 91
91
 91
Accounts payable98
 111
90
 111
Accrued expenses50
 39
59
 39
Payables to affiliates21
 33
26
 33
Customer deposits36
 35
36
 35
Regulatory liabilities49
 59
43
 59
Other16
 7
33
 7
Total current liabilities366
 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 credits643
 628
655
 628
Non-pension postretirement benefits obligations16
 17
16
 17
Regulatory liabilities596
 606
580
 606
Other114
 50
114
 50
Total deferred credits and other liabilities1,369

1,301
1,365

1,301
Total liabilities3,139

3,079
3,204

3,079
Commitments and contingencies
 

 

Shareholder's equity      
Common stock914
 914
914
 914
Retained earnings607
 595
606
 595
Total shareholder's equity1,521

1,509
1,520

1,509
Total liabilities and shareholder's equity$4,660

$4,588
$4,724

$4,588

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Three Months Ended March 31, 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, 2019$914
 $607
 $1,521
$914
 $607
 $1,521
Net income—
 30
 30
Common stock dividends—
 (29) (29)
Balance, June 30, 2019$914
 $608
 $1,522
Net income—
 33
 33
Common stock dividends—
 (35) (35)
Balance, September 30, 2019$914
 $606
 $1,520


Three Months Ended March 31, 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, 2018$764
 $566
 $1,330
$764
 $566
 $1,330
Net income—
 26
 26
Common stock dividends—
 (4) (4)
Contributions from parent150
 —
 150
Balance, June 30, 2018$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
March 31,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
(In millions)2019 20182019 2018 2019 2018
Operating revenues          
Electric operating revenues$271
 $311
$417
 $406
 $964
 $983
Revenues from alternative revenue programs1
 (2)1
 (1) —
 (4)
Operating revenues from affiliates1
 1
1
 1
 2
 2
Total operating revenues273
 310
419
 406
 966
 981
Operating expenses          
Purchased power131
 155
207
 188
 463
 465
Purchased power from affiliates8
 6
3
 10
 16
 21
Operating and maintenance47
 54
54
 52
 142
 146
Operating and maintenance from affiliates34
 36
32
 33
 99
 104
Depreciation and amortization31
 33
43
 38
 114
 107
Taxes other than income1
 3
1
 1
 4
 4
Total operating expenses252
 287
340
 322
 838
 847
Operating income21

23
79

84
 128

134
Other income and (deductions)          
Interest expense, net(14) (16)(15) (16) (44) (48)
Other, net3
 1
1
 1
 5
 2
Total other income and (deductions)(11) (15)(14) (15) (39) (46)
Income before income taxes10
 8
65
 69
 89
 88
Income taxes—
 1
2
 8
 2
 12
Net income$10

$7
$63

$61

$87

$76
Comprehensive income$10
 $7
$63
 $61
 $87
 $76

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,		Nine Months Ended
September 30,
(In millions)2019
20182019
2018
Cash flows from operating activities      
Net income$10
 $7
$87
 $76
Adjustments to reconcile net income to net cash flows provided by operating activities:      
Depreciation and amortization31
 33
114
 107
Deferred income taxes and amortization of investment tax credits—
 2
2
 24
Other non-cash operating activities5
 9
21
 24
Changes in assets and liabilities:      
Accounts receivable13
 (5)(44) (66)
Receivables from and payables to affiliates, net(4) (4)(4) (3)
Inventories1
 —
(4) (2)
Accounts payable and accrued expenses12
 30
27
 21
Income taxes(1) —
5
 (3)
Pension and non-pension postretirement benefit contributions—
 (6)—
 (6)
Other assets and liabilities(7) (7)(18) (12)
Net cash flows provided by operating activities60
 59
186
 160
Cash flows from investing activities      
Capital expenditures(128) (63)(300) (247)
Other investing activities—
 (1)—
 (1)
Net cash flows used in investing activities(128) (64)(300) (248)
Cash flows from financing activities      
Changes in short-term borrowings77
 28
49
 37
Proceeds from short-term borrowings with maturities greater than 90 days—
 125
Repayments of short-term borrowings with maturities greater than 90 days(125) —
Issuance of long-term debt150
 —
Retirement of long-term debt(4) (8)(13) (22)
Contributions from parent155
 —
Dividends paid on common stock(12) (9)(100) (46)
Contributions from parent5
 —
Other financing activities(1) —
Net cash flows provided by financing activities66
 11
115
 94
(Decrease) increase in cash, cash equivalents and restricted cash(2) 6
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$28

$37
$31

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

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
ASSETS      
Current assets      
Cash and cash equivalents$6
 $7
$13
 $7
Restricted cash and cash equivalents3
 4
3
 4
Accounts receivable, net      
Customer85
 95
Other52
 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 affiliates1
 1
1
 1
Inventories, net32
 33
37
 33
Prepaid utility taxes9
 —
Regulatory assets53
 40
48
 40
Other6
 5
7
 5
Total current assets238
 240
307
 240
Property, plant and equipment, net3,041
 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 assets377
 386
370
 386
Prepaid pension asset63
 67
56
 67
Other64
 40
59
 40
Total deferred debits and other assets504
 493
485
 493
Total assets(a)
$3,783
 $3,699
$3,916
 $3,699

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


(In millions)March 31, 2019 December 31, 2018September 30, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Short-term borrowings$216
 $139
$63
 $139
Long-term debt due within one year19
 18
19
 18
Accounts payable139
 154
139
 154
Accrued expenses38
 35
40
 35
Payables to affiliates24
 28
24
 28
Customer deposits26
 26
26
 26
Regulatory liabilities20
 18
25
 18
Other10
 4
11
 4
Total current liabilities492
 422
347
 422
Long-term debt1,165
 1,170
1,305
 1,170
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits539
 535
569
 535
Non-pension postretirement benefit obligations17
 17
18
 17
Regulatory liabilities395
 402
365
 402
Other46
 27
44
 27
Total deferred credits and other liabilities997
 981
996
 981
Total liabilities(a)
2,654
 2,573
2,648
 2,573
Commitments and contingencies
 

 

Shareholder's equity      
Common stock984
 979
1,134
 979
Retained earnings145
 147
134
 147
Total shareholder's equity1,129

1,126
1,268

1,126
Total liabilities and shareholder's equity$3,783

$3,699
$3,916

$3,699
__________
(a)ACE’s consolidated total assets include $22$18 million and $23 million at March 31,September 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 $54$46 million and $59 million at March 31,September 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)
Three Months Ended March 31, 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 parent

5
 —
 5
5
 —
 5
Balance, March 31, 2019$984

$145
 $1,129
$984
 $145
 $1,129
Net income—
 14
 14
Common stock dividends—
 (12) (12)
Contributions from parent150
 —
 150
Balance, June 30, 2019$1,134

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


Three Months Ended March 31, 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, 2018$912
 $129
 $1,041
$912
 $129
 $1,041
Net income—
 8
 8
Common stock dividends—
 (10) (10)
Balance, June 30, 2018$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
56
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)


Note 1 — Significant Accounting Policies



Index to Combined Notes To Consolidated Financial Statements
The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the Registrants to which the footnotes apply:
Applicable Notes
Registrant123456789101112131415161718
Exelon Corporation..................
Exelon Generation Company, LLC..................
Commonwealth Edison Company.. ...  .... . ...
PECO Energy Company.. ...  .... . ...
Baltimore Gas and Electric Company.. ...  .... . ...
Pepco Holdings LLC.. ...  .... . ...
Potomac Electric Power Company.. ...  .... . ...
Delmarva Power & Light Company.. ...  .... . ...
Atlantic City Electric Company.. ...  .... . ...

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

1. 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 March 31,September 30, 2019 and 2018 and for the three and nine months then ended are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 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

57
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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

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

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 March 31,September 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 March 31,September 30, 2019. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early adopt where applicable.financial statements. The Registrants have assessed other FASB issuances of new standards which are not listed below givenas the current expectation thatRegistrants do not expect such standards will not significantlyto have a material impact the Registrants'to their financial reporting.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 have goodwill as of March 31, 2019. Thisdo not expect the updated guidance is not currently expected to have a material impact the Registrants’to their financial reporting.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 impactsdo not expect that this guidance will have a significant impact on their consolidated financial statements.

58
Table of this standard.Contents

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 March 31,September 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 March 31, 2019 and December 31, 2018, Exelon and Generation collectively had significant interests in sevenseveral 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.

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Table of Contents
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.

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

Note 2 — Variable Interest Entities


As of March 31,September 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 March 31, 2019 provides corporate and December 31, 2018, Exelon's, PHI'sadministrative services to CENG and ACE's consolidated VIE consist of:
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 March 31, 2019 and December 31, 2018, ComEd, PECO, BGE, Pepco and DPL did not have any material consolidated VIEs.
As of March 31, 2019 and December 31, 2018, Exelon and Generation provided the following support to their respective consolidated VIEs:
Generation provides 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.
Generation provides approximately $32 million in credit support for the retail power and gas companies for which Generation is the sole supplierCENG member rights 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. However, pursuant to amendments dated March 31, 2015, the energy obligations under the Ginna Nuclear Power Plant (Ginna) PPAs were suspended during the term of the RSSA, through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017,
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 22 — Commitments and Contingencies of the Exelon 2018 Form 10-K for additional information.
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 and EDF share in the$688 $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and
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 March 31, 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 theGeneration related to certain solar and wind entities.


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


Note 2 — Variable Interest Entities
NJBPU

In 2017, Generation’s interests in an amount sufficientEGRP were contributed to fundand are pledged for the principalEGR IV non-recourse debt project financing structure. Refer to Note 11— Debt and interest payments on transition bonds and related taxes, expenses and fees. During the three months ended March 31, 2019, ACE transferred $4 million to ATF. During the three months ended March 31, 2018, ACE transferred $8 million to ATF.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 March 31,September 30, 2019 and December 31, 2018, are as follows:Exelon's, PHI's and ACE's consolidated VIE consists of:
 March 31, 2019 December 31, 2018
 
Exelon(a)
 Generation 
PHI(a)
 ACE 
Exelon(a)
 Generation 
PHI(a)
 ACE
Current assets$645
 $639
 $6
 $3
 $938
 $931
 $7
 $4
Noncurrent assets9,235
 9,210
 25
 19
 9,071
 9,045
 26
 19
Total assets$9,880

$9,849

$31
 $22

$10,009

$9,976

$33
 $23
Current liabilities$748
 $725
 $23
 $19
 $274
 $252
 $22
 $19
Noncurrent liabilities2,831
 2,790
 41
 35
 3,280
 3,233
 47
 40
Total liabilities$3,579

$3,515

$64
 $54

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

Generation
PHI(a)
 ACE 
Exelon(a)
 Generation 
PHI(a)
 ACE
Cash and cash equivalents$125
 $125
 $—
 $—
 $414
 $414
 $—
 $—
Restricted cash and cash equivalents58
 55
 3
 3
 66
 62
 4
 4
Accounts receivable, net               
Customer152
 152
 —
 —
 146
 146
 —
 —
Other23
 23
 —
 —
 23
 23
 —
 —
Inventory, net               
Materials and supplies213
 213
 —
 —
 212
 212
 —
 —
Other current assets51
 48
 3
 —
 52
 49
 3
 —
Total current assets622

616

6
 3
 913

906

7
 4
Property, plant and equipment, net6,147
 6,147
 —
 —
 6,145
 6,145
 —
 —
NDT funds2,520
 2,520
 —
 —
 2,351
 2,351
 —
 —
Other noncurrent assets257
 232
 25
 19
 258
 232
 26
 19
Total noncurrent assets8,924

8,899

25
 19
 8,754

8,728

26
 19
Total assets$9,546

$9,515

$31
 $22
 $9,667

$9,634

$33
 $23
Long-term debt due within one year$567
 $545
 $22
 $19
 $87
 $66
 $21
 $18
Accounts payable120
 120
 —
 —
 96
 96
 —
 —
Accrued expenses42
 41
 1
 —
 72
 72
 1
 1
Unamortized energy contract liabilities13
 13
 —
 —
 15
 15
 —
 —
Other current liabilities6
 6
 —
 —
 3
 3
 —
 —
Total current liabilities748
 725
 23
 19
 273
 252
 22
 19
Long-term debt565
 524
 41
 35
 1,072
 1,025
 47
 40
Asset retirement obligations2,190
 2,190
 —
 —
 2,160
 2,160
 —
 —
Unamortized energy contract liabilities—
 —
 —
 —
 1
 1
 —
 —
Other noncurrent liabilities69
 69
 —
 —
 42
 42
 —
 —
Total noncurrent liabilities2,824
 2,783
 41
 35
 3,275
 3,228
 47
 40
Total liabilities$3,572
 $3,508
 $64
 $54
 $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 March 31, 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 March 31, 2019 and December 31, 2018, the Utility Registrants did not have any material unconsolidated VIEs.
As of March 31,September 30, 2019 and December 31, 2018, Exelon and Generation had significant unconsolidated variable interests in sevenseveral VIEs 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, respectively, as of March 31, 2019. These immaterial VIEs are equity and debt securities in energy development companies. As of March 31, 2019, 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, 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:
March 31, 2019
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
Total assets(a)
$601
 $463
 $1,064
Total liabilities(a)
42
 223
 265
Exelon's ownership interest in VIE(a)
—
 214
 214
Other ownership interests in VIE(a)
559
 26
 585
Registrants’ maximum exposure to loss:    
Carrying amount of equity method investments—
 214
 214
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

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Table of their variable interestsContents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in these VIEs.millions, except per share data, unless otherwise noted)

Note 2 — Variable Interest Entities


As of 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. On September 17, 2018, Oyster CreekJersey, which permanently ceased generation operations.operations on September 17, 2018. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and a private letter ruling from the IRS, which were satisfied in the second quarter 2019. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter, which was immaterial.
Under the terms of the transaction, Generation will transfertransferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. In addition to the assumption of liability for the full decommissioning and ongoing management of spent fuel, other consideration to be received in the transaction is contingent on several factors, including a requirement that Generation deliver a minimum NDT fund balance at closing, subject to adjustment for specific terms that include income taxes that would be imposed on any net unrealized built-in gains and certain decommissioning activities to be performed during the pre-close period after the unit shuts down in the fall of 2018 and prior to the anticipated close of the transaction. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events.

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

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 $888 million and $765 million of Assets and Liabilities held for sale, respectively, at March 31, 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, in the third quarter of 2018, Exelon and Generation recognized an $84 million and a $9 million pre-tax charge to Operating and maintenance expense.
Completionexpense in the third quarter of the transaction contemplated by the sale agreement is subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC2018 and other regulatory approvals, and a private letter ruling from the IRS, which was received in April 2019. Generation currently anticipates satisfaction of the remaining closing conditions to occur in the second halfquarter of 2019.2019, respectively. See Note 13 — Nuclear Decommissioning for additional information.

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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 threenine months ended March 31,September 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 March 31,September 30, 2019:
  Contract Assets Contract Liabilities
  Exelon Generation Exelon Generation
Balance as of January 1, 2018 $283
 $283
 $35
 $35
Consideration received or due (146) (146) 179
 465
Revenues recognized 50
 50
 (187) (458)
Balance at December 31, 2018 187
 187
 27
 42
Consideration received or due (109) (109) 65
 198
Revenues recognized 92
 92
 (66) (192)
Balance at September 30, 2019 170
 170
 26
 48
  Contract Assets Contract Liabilities
  Exelon Generation Exelon Generation
Balance as of January 1, 2018 $283
 $283
 $35
 $35
Increases as a result of changes in the estimate of the stage of completion 50
 50
 —
 —
Increases as a result of additional cash received or due —
 —
 179
 465
Amounts reclassified into receivables or recognized into revenues (146) (146) (187) (458)
Balance at December 31, 2018 187
 187
 27
 42
Increases as a result of changes in the estimate of the stage of completion 26
 26
 —
 —
Increases as a result of additional cash received or due —
 —
 21
 63
Amounts reclassified into receivables or recognized into revenues (26) (26) (23) (66)
Balance at March 31, 2019 $187
 $187
 $25
 $39

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 March 31,September 30, 2019 and December 31, 2018, the Utility Registrants' contract liabilities were immaterial.

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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 March 31,September 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 Total
Exelon156
 341
 142
 74
 244
 957
Generation215
 442
 197
 89
 244
 1,187
 2019 2020 2021 2022 2023 and thereafter Total
Exelon$393
 $273
 $112
 $50
 $142
 $970
Generation493
 331
 126
 50
 142
 1,142

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.

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

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 ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Remaining lease terms1-87 1-37 1-34 1-15 1-87 1-13 1-13 1-13 1-81-87 1-37 1-6 1-15 1-87 1-13 1-13 1-13 1-8
Options to extend the term3-30 3-30 3-10 N/A N/A 3-30 5 3-30 N/A3-30 3-30 5 N/A N/A 3-30 5 3-30 N/A
Options to terminate within1-3 2 N/A N/A 3 N/A N/A N/A N/A2-14 2 4 N/A 3 N/A N/A N/A N/A
The components of lease costs for the three months ended March 31,September 30, 2019 were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating lease costs$68
 $46
 $1
 $—
 $8
 $10
 $3
 $3
 $1
Variable lease costs73
 68
 —
 —
 —
 2
 —
 1
 —
Short-term lease costs9
 8
 —
 —
 —
 —
 —
 —
 —
Total lease costs (a)
$150
 $122
 $1
 $—
 $8
 $12
 $3
 $4
 $1
 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 $3$29 million, $2$28 million, $1 million and $1 million of sublease income recorded at Exelon, Generation, PHI and DPL.DPL, respectively

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

Note 5 — Leases

The components of lease costs for the nine months ended September 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
__________
(a)Excludes $48 million, $42 million, $6 million and $6 million of sublease income recorded at Exelon, Generation, PHI and 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 March 31,September 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$1,465
 $1,027
 $5
 $2
 $97
 $314
 $67
 $75
 $26
$1,374
 $926
 $10
 $2
 $83
 $304
 $66
 $75
 $24
                                  
Operating lease liabilities                                  
Other current liabilities249
 173
 3
 1
 31
 36
 8
 11
 6
242
 170
 3
 —
 32
 35
 8
 11
 5
Other deferred credits and other liabilities1,395
 1,023
 4
 1
 66
 284
 60
 72
 20
1,355
 949
 8
 1
 50
 279
 60
 74
 19
Total operating lease liabilities$1,644
 $1,196
 $7
 $2
 $97
 $320
 $68
 $83
 $26
$1,597
 $1,119
 $11
 $1
 $82
 $314
 $68
 $85
 $24
__________
(a)Exelon's and Generation's operating ROU assets and lease liabilities include $631$542 million and $778$703 million, respectively, related to contracted generation.
The weighted average remaining lease terms, in years, and discount rates for operating leases as of March 31,September 30, 2019 were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Remaining lease term10.1
 10.6
 4.7
 4.3
 5.6
 9.0
 9.6
 9.5
 5.3
Discount rate4.5% 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


66
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Remaining lease term10.0
 10.7
 2.9
 4.4
 5.6
 9.4
 9.9
 9.8
 5.3
Discount rate4.6% 4.8% 3.3% 3.4% 3.6% 4.1% 3.9% 3.9% 3.5%
Table of Contents

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


Future minimum lease payments for operating leases as of March 31, 2019 were as follows:
Note 5 — Leases
YearExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
2019$214
 $154
 $2
 $1
 $19
 $33
 $8
 $7
 $5
2020289
 202
 2
 1
 34
 43
 9
 12
 5
2021244
 162
 2
 —
 32
 42
 9
 11
 5
2022174
 112
 1
 —
 16
 40
 8
 11
 4
2023139
 99
 —
 —
 —
 39
 8
 10
 3
Remaining years1,052
 840
 —
 —
 18
 194
 42
 52
 7
Total2,112
 1,569
 7
 2
 119
 391
 84
 103
 29
Interest468
 373
 —
 —
 22
 71
 16
 20
 3
Total operating lease liabilities$1,644
 $1,196
 $7
 $2
 $97
 $320
 $68
 $83
 $26

Future minimum lease payments for operating leases under the prior lease accounting guidance as of December 31, 2018 were as follows:
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)
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
$140
 $33
 $7
 $5
 $35
 $48
 $11
 $14
 $7
2020149
 46
 5
 5
 35
 46
 10
 13
 6
149
 46
 5
 5
 35
 46
 10
 13
 6
2021143
 46
 4
 5
 33
 43
 9
 12
 5
143
 46
 4
 5
 33
 43
 9
 12
 5
2022126
 47
 4
 5
 18
 42
 8
 12
 5
126
 47
 4
 5
 18
 42
 8
 12
 5
202397
 46
 3
 5
 3
 39
 8
 10
 4
97
 46
 3
 5
 3
 39
 8
 10
 4
Remaining years723
 545
 —
 —
 19
 159
 40
 35
 5
723
 545
 —
 —
 19
 159
 40
 35
 5
Total minimum future lease payments$1,378
 $763
 $23
 $25
 $143
 $377
 $86
 $96
 $32
$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 threenine months ended March 31,September 30, 2019 were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating cash flows from operating leases$78
 $52
 $1
 $—
 $14
 $8
 $2
 $2
 $1
 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 threenine months ended March 31,September 30, 2019 were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating leases$70
 $11
 $6
 $—
 $1
 $20
 $7
 $9
 $4

 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating leases$20
 $9
 $—
 $—
 $—
 $11
 $4
 $4
 $3
Lessor

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

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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 March 31,September 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$4
 $3
 $—
 $—
 $—
 $1
 $—
 $1
 $—
$30
 $29
 $—
 $—
 $—
 $1
 $—
 $1
 $—
Variable lease income$52
 $52
 $—
 $—
 $—
 $—
 $—
 $—
 $—
80
 80
 —
 —
 —
 —
 —
 —
 —

The components of lease income for the nine months ended September 30, 2019 were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating lease income$48
 $44
 $—
 $—
 $—
 $3
 $—
 $3
 $—
Variable lease income209
 206
 —
 —
 —
 3
 —
 3
 —

Future minimum lease payments to be recovered under operating leases as of March 31,September 30, 2019 were as follows:
YearExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
2019$4
 $3
 $—
 $—
 $—
 $1
 $—
 $1
 $—
202051
 46
 —
 —
 —
 4
 —
 3
 —
202150
 45
 —
 —
 —
 4
 1
 3
 —
202250
 45
 —
 —
 —
 5
 —
 4
 —
202349
 45
 —
 —
 —
 4
 —
 3
 —
Remaining years314
 271
 1
 3
 1
 38
 —
 38
 —
Total$518
 $455
 $1
 $3
 $1
 $56
 $1
 $52
 $—


68
YearExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
2019$47
 $43
 $—
 $—
 $—
 $4
 $—
 $3
 $—
202051
 46
 —
 —
 —
 4
 —
 3
 —
202150
 45
 —
 —
 —
 4
 —
 3
 —
202250
 45
 —
 —
 —
 4
 —
 3
 —
202349
 45
 —
 —
 —
 4
 —
 3
 —
Remaining years315
 271
 1
 3
 1
 39
 1
 38
 —
Total$562
 $495
 $1
 $3
 $1
 $59
 $1
 $53
 $—

Table of Contents
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 Increase Approved Revenue Requirement Increase (Decrease) Approved ROEApproval 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, 2019
PECO - Pennsylvania (Electric)March 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
(a) 
$70
(a) 
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.

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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 TimingFiling DateRequested Revenue Requirement (Decrease) IncreaseRequested ROEExpected Approval Timing
Pepco - Maryland (Electric)January 15, 2019 (amended April 30, 2019)$27
 10.3%Third quarter of 2019
ComEd - Illinois (Electric)(a)
April 8, 2019$(6) 8.91%December 2019April 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 $84 million, $40 million and $36 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.
Transmission Formula Rates
Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation).
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 (Decrease) IncreaseTotal Revenue Requirement Increase (Decrease) 
Allowed Return on Rate Base(c)
Allowed ROE(d)
ComEd$21
$(16)$5
 8.21%11.50%
BGE(10)(23)(19)
(b) 
7.35%10.50%
Pepco15
11
26

7.75%10.50%
DPL17
(1)16

7.14%10.50%
ACE11
(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

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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. ThePECO’s initial formula rate filing includesincluded a requested increase of  $22 million to PECO’s annual transmission revenues andrevenue requirement, which reflected a requested rate of return on common equityROE of  11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017.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 May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. On February 8,July 22, 2019, PECO and the active parties reached an agreement in principle to settle this case. The presiding Administrative Law Judge has since suspended the procedural schedule in order for PECO and the active parties to continue working towards finalizing a settlement. On April 15, 2019, PECO and the activeother parties filed with FERC a status update withsettlement agreement, which includes a ROE of 10.35%, inclusive of a 50 basis point adder for being a member of a RTO. The settlement did not have a material impact on PECO’s 2017, 2018, or 2019 annual transmission revenue requirements. A final order from FERC is expected before the presiding Administrative

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

Law Judge requesting an additional 45 days to file a settlement.end of the first quarter of 2020. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO madeOther State Regulatory Matters
Energy Efficiency Formula Rate. ComEd filed its first annual energy efficiency formula rate update which included awith the ICC on May 23, 2019. The filing establishes the revenue decrease of $6 million.requirement used to set the rates that will take effect in January 2020 after the ICC’s review and approval. The revenue decrease of $6 million included an approximately $20 million reduction asrequirement requested is based on a resultreconciliation of the tax savings associated with2018 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 TCJA.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 updated transmissionMDPSC found that a multi-year rate was effective June 1, 2018, subjectplan, based on a historic test year and allowing up to refund.
Other State Regulatory Mattersthree 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 allowsallowed 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

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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, must beginbegan 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). ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s transmission formula rates currently do not provide for the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA.
On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. As a result of the FERC’s order, ComEd, BGE, Pepco, DPL and ACE took a charge to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017 reducing their associated transmission-related income tax regulatory assets for the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula. See above for additional information regarding PECO's transmission formula rate filing.
On December 18, 2017, BGE filed for clarification and rehearing of FERC’s November 16, 2017 order and on February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.
On September 7, 2018, FERC issued orders rejecting BGE’s December 18, 2017 request for rehearing and clarification and ComEd's, Pepco's, DPL's and ACE's February 23, 2018 (as amended on July 9, 2018) filings, citing the lack of timeliness of the requests to recover amounts that would have been previously amortized, but indicating

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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 $76$80 million, $51$52 million, $15$16 million, $10$12 million, $3$4 million, $5$6 million and $2 million, respectively, as of March 31,September 30, 2019.
Regulatory Assets and Liabilities
RegulatoryThe Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2018.2018, 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.

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Note 6 — Regulatory Matters

ComEd. Regulatory assets increased $122 million primarily due to an increase of $186 million in Energy Efficiency Costs and $32 million Renewable Energy partially offset by a decrease of $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 $90 million primarily due to a decrease of $40 million in Deferred Income Taxes and $43 million in Removal Costs.
Pepco. Regulatory assets decreased $84 million primarily due to a decrease of $39 million in Electric Energy and Natural Gas Costs, $26 million in DC PLUG 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 $42 million primarily due to a decrease of $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
March 31, 2019$64
 $7
 $—
 $49
 $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.
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 three months ended March 31,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.


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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 the same day, Generation filed certain Supplemental Information with the NJBPU providing proprietary information that was requested in the application but which could not be shared with PSEG. 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 $21 million and $31 million for the three and nine months ended September 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, 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.
Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 8 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.
Federal Regulatory Matters
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) with Maryland Department of the Environment (MDE)from 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.

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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 March 31,September 30, 2019, $38$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.

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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 Pacific Gas and Electric Company (PG&E)PG&E through a PPA. As of March 31,September 30, 2019, Generation had approximately $750$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 $1,970$1,930 million of additional net long-lived assets as of March 31,September 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.
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

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

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, ExelonGeneration announced that Generation willit would permanently cease generation operations at TMI on or aboutTMI. On September 30, 2019. TMI is currently committed to operate through May 2019 and is licensed to operate through 2034. Generation has filed the required market and regulatory notifications to shut down the plant. PJM has subsequently notified Generation that it has not identified any reliability issues and has approved the deactivation of TMI as proposed. On April 5,20, 2019, Generation filed the post shutdown decommissioning activities report (PSDAR) with the NRC detailing the plans for TMI after its final shutdown.permanently ceased generation operations at TMI.

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Note 8 — Early Plant Retirements

On February 2, 2018, ExelonGeneration announced that Generation willit 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.
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 nine months ended March 31,September 30, 2019 and 2018 are summarized in the table below.
 Three Months Ended
March 31,		 Three Months Ended September 30, Nine Months Ended September 30,
Income statement expense (pre-tax) 2019 2018 2019 2018 2019 2018
Depreciation and amortization(a)
            
Accelerated depreciation(b)
 $74
 $137
 $71
 $152
 $216
 $441
Accelerated nuclear fuel amortization 5
 15
 3
 18
 13
 52
Operating and maintenance(c)(b)
 (83) 26
 39
 4
 (44) 32
Total $(4) $178
 $113
 $174
 $185
 $525
_________
(a)Reflects incremental accelerated depreciation and amortization for TMI for the three and nine months ended March 31,September 30, 2019. Reflects incremental accelerated depreciation for TMI and Oyster Creek for the three and nine months ended March 31,September 30, 2018. The Oyster Creek amounts are from February 2, 2018 through March 31,September 17, 2018. The TMI amounts are through September 20, 2019.
(b)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c)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.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.

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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 currentthen-current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 is currentlywas 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 are duewere 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.

77
Table of Contents
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. On May 8, 2019, FERC hasissued a deficiency letter to ISO-NE seeking additional information on the Inventoried Energy Program proposal, and ISO-NE filed a response on June 6, 2019. On August 5, 2019, FERC allowed 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 rules by Octoberto April 15, 2019.2020.
The following table provides the balance sheet amounts as of March 31,September 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.
  September 30, 2019
Asset Balances  
Materials and supplies inventory $31
Fuel inventory 5
Completed plant, net 889
Construction work in progress 7
Liability Balances  
Asset retirement obligation (2)

  March 31, 2019
Asset Balances  
Materials and supplies inventory $30
Fuel inventory 22
Completed plant, net 900
Construction work in progress 2
Liability Balances  
Asset retirement obligation (1)

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

9. Fair Value of Financial Assets and Liabilities (All Registrants)
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 March 31,September 30, 2019 and December 31, 2018:2018. The Registrants have no financial liabilities classified as Level 1.
ExelonThe 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.

78
 March 31, 2019
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities$1,254
 $—
 $1,254
 $—
 $1,254
Long-term debt (including amounts due within one year)(a)
35,468
 —
 35,066
 2,188
 37,254
Long-term debt to financing trusts(b)
390
 —
 —
 411
 411
SNF obligation1,178
 —
 989
 —
 989
Table of Contents
 December 31, 2018
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities$714
 $—
 $714
 $—
 $714
Long-term debt (including amounts due within one year)(a)
35,424
 —
 33,711
 2,158
 35,869
Long-term debt to financing trusts(b)
390
 —
 —
 400
 400
SNF obligation1,171
 —
 949
 —
 949
Generation
 March 31, 2019
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)
$8,747
 $—
 $7,641
 $1,443
 $9,084
SNF obligation1,178
 —
 989
 —
 989
 December 31, 2018
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)
$8,793
 $—
 $7,467
 $1,443
 $8,910
SNF obligation1,171
 —
 949
 —
 949

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

Exelon $36,304
 $38,056
 $2,541
 $40,597
 $35,424
 $33,711
 $2,158
 $35,869
Generation 8,613
 7,962
 1,398
 9,360
 8,793
 7,467
 1,443
 8,910
ComEd 8,196
 9,622
 —
 9,622
 8,101
 8,390
 —
 8,390
PECO 3,404
 3,891
 50
 3,941
 3,084
 3,157
 50
 3,207
BGE 3,270
 3,678
 —
 3,678
 2,876
 2,950
 —
 2,950
PHI 6,494
 5,993
 1,093
 7,086
 6,259
 5,436
 665
 6,101
Pepco 2,860
 3,249
 395
 3,644
 2,719
 2,901
 196
 3,097
DPL 1,495
 1,437
 232
 1,669
 1,494
 1,303
 193
 1,496
ACE 1,324
 1,034
 466
 1,500
 1,188
 987
 275
 1,262
Long-Term Debt to Financing Trusts(a)

Exelon $390
 $—
 $426
 $426
 $390
 $—
 $400
 $400
ComEd 205
 —
 223
 223
 205
 —
 209
 209
PECO 184
 —
 203
 203
 184
 —
 191
 191
SNF Obligation
Exelon $1,193
 $1,017
 $—
 $1,017
 $1,171
 $949
 $—
 $949
Generation 1,193
 1,017
 —
 1,017
 1,171
 949
 —
 949
 March 31, 2019
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities$322
 $—
 $322
 $—
 $322
Long-term debt (including amounts due within one year)(a)
8,194
 —
 8,855
 —
 8,855
Long-term debt to financing trusts(b)
205
 —
 —
 215
 215
 December 31, 2018
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)
$8,101
 $—
 $8,390
 $—
 $8,390
Long-term debt to financing trusts(b)
205
 —
 —
 209
 209
PECO
 March 31, 2019
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)
$3,084
 $—
 $3,295
 $50
 $3,345
Long-term debt to financing trusts(b)
184
 —
 —
 196
 196
 December 31, 2018
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)
$3,084
 $—
 $3,157
 $50
 $3,207
Long-term debt to financing trusts(b)
184
 —
 —
 191
 191
BGE
 March 31, 2019
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities$106
 $—
 $106
 $—
 $106
Long-term debt (including amounts due within one year)(a)
2,876
 —
 3,051
 —
 3,051

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

 December 31, 2018
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities$35
 $—
 $35
 $—
 $35
Long-term debt (including amounts due within one year)(a)
2,876
 —
 2,950
 —
 2,950
PHI
 March 31, 2019
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities$326
 $—
 $326
 $—
 $326
Long-term debt (including amounts due within one year)(a)
6,244
 —
 5,608
 695
 6,303
 December 31, 2018
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities$179
 $—
 $179
 $—
 $179
Long-term debt (including amounts due within one year)(a)
6,259
 —
 5,436
 665
 6,101
Pepco
 March 31, 2019
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities$105
 $—
 $105
 $—
 $105
Long-term debt (including amounts due within one year)(a)
2,720
 —
 3,000
 208
 3,208
 December 31, 2018
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities$40
 $—
 $40
 $—
 $40
Long-term debt (including amounts due within one year)(a)
2,719
 —
 2,901
 196
 3,097
DPL
 March 31, 2019
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities$5
 $—
 $5
 $—
 $5
Long-term debt (including amounts due within one year)(a)
1,495
 —
 1,345
 204
 1,549

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

 December 31, 2018
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(a)
$1,494
 $—
 $1,303
 $193
 $1,496
ACE
 March 31, 2019
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities$216
 $—
 $216
 $—
 $216
Long-term debt (including amounts due within one year)(a)
1,184
 —
 1,004
 283
 1,287
 December 31, 2018
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities$139
 $—
 $139
 $—
 $139
Long-term debt (including amounts due within one year)(a)
1,188
 —
 987
 275
 1,262
_____________
(a)Includes unamortized debt issuance costs which are not fair valued of $216 million, $49 million, $67 million, $22 million, $18 million, $14 million, $33 million, $12 million and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of March 31, 2019. Includes unamortized debt issuance costs which are not fair valued of $216 million, $51 million, $63 million, $23 million, $18 million, $14 million, $34 million, $12 million and $7 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of December 31, 2018.
(b)Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of March 31, 2019. Includes unamortized debt issuance costs which are not fair valued of less than $1 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2018.valued.
Recurring Fair Value Measurements
Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
Generation and Exelon
In accordance with the applicable guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a practical expedient are no longer classified within the fair value hierarchy and are included under "Not subject to leveling" in the table below.
The following tables present assets and liabilities measured and recorded at fair value in Exelon's and Generation’sthe Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31,September 30, 2019 and December 31, 2018:

Exelon and Generation
 Exelon Generation
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)
$1,719
 $—
 $—
 $—
 $1,719
 $896
 $—
 $—
 $—
 $896
NDT fund investments        
         
Cash equivalents(b)
315
 78
 —
 —
 393
 315
 78
 —
 —
 393
Equities3,121
 1,727
 —

1,314
 6,162
 3,121
 1,727
 —

1,314
 6,162
Fixed income                   
Corporate debt—
 1,473
 259
 —
 1,732
 —
 1,473
 259
 —
 1,732
U.S. Treasury and agencies1,777
 152
 —
 —
 1,929
 1,777
 152
 —
 —
 1,929
Foreign governments—
 56
 —
 —
 56
 —
 56
 —
 —
 56
State and municipal debt—
 85
 —
 —
 85
 —
 85
 —
 —
 85
Other(c)
—
 23
 —
 979
 1,002
 —
 23
 —
 979
 1,002

79
Table of Contents
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

Generation ExelonExelon Generation
As of March 31, 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)
$370
 $—
 $—
 $—
 $370
 $817
 $—
 $—
 $—
 $817
NDT fund investments        
         
Cash equivalents(b)
369
 74
 —
 —
 443
 369
 74
 —
 —
 443
Equities3,060
 1,753
 1

1,545
 6,359
 3,060
 1,753
 1

1,545
 6,359
Fixed income                   
Corporate debt—
 1,545
 236
 1
 1,782
 —
 1,545
 236
 1
 1,782
U.S. Treasury and agencies2,033
 112
 —
 —
 2,145
 2,033
 112
 —
 —
 2,145
Foreign governments—
 43
 —
 —
 43
 —
 43
 —
 —
 43
State and municipal debt—
 110
 —
 —
 110
 —
 110
 —
 —
 110
Other(c)
—
 26
 —
 935
 961
 —
 26
 —
 935
 961
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 subtotal2,033

1,836

236
 936

5,041

2,033

1,836

236
 936

5,041
1,777

1,789

259
 979

4,804

1,777

1,789

259
 979

4,804
Middle market lending—
 —
 303
 406
 709
 —
 —
 303
 406
 709
—
 —
 255
 445
 700
 —
 —
 255
 445
 700
Private equity—
 —
 —
 352
 352
 —
 —
 —
 352
 352
—
 —
 —
 398
 398
 —
 —
 —
 398
 398
Real estate—
 —
 —
 535
 535
 —
 —
 —
 535
 535
—
 —
 —
 581
 581
 —
 —
 —
 581
 581
NDT fund investments subtotal(d)
5,462

3,663

540
 3,774

13,439

5,462

3,663

540
 3,774

13,439
5,213

3,594

514
 3,717

13,038

5,213

3,594

514
 3,717

13,038
Rabbi trust investments        
         
        
         
Cash equivalents4
 —
 —
 —
 4
 47
 —
 —
 —
 47
49
 —
 —
 —
 49
 4
 —
 —
 —
 4
Mutual funds25
 —
 —
 —
 25
 74
 —
 —
 —
 74
77
 —
 —
 —
 77
 24
 —
 —
 —
 24
Fixed income—
 —
 —
 —
 —
 —
 14
 —
 —
 14
—
 13
 —
 —
 13
 —
 —
 —
 —
 —
Life insurance contracts—
 23
 —
 —
 23
 —
 71
 39
 —
 110
—
 76
 40
 —
 116
 —
 24
 —
 —
 24
Rabbi trust investments subtotal(e)
29

23

—
 —

52

121

85

39
 —

245
Rabbi trust investments subtotal126

89

40
 —

255

28

24

—
 —

52
Commodity derivative assets                                      
Economic hedges273
 2,164
 1,442
 —
 3,879
 273
 2,164
 1,442
 —
 3,879
533
 1,488
 1,817
 —
 3,838
 533
 1,488
 1,817
 —
 3,838
Proprietary trading—
 74
 104
 —
 178
 —
 74
 104
 —
 178
—
 54
 156
 —
 210
 —
 54
 156
 —
 210
Effect of netting and allocation of collateral(f)(g)
(294) (1,836) (820) —
 (2,950) (294) (1,836) (820) —
 (2,950)
Effect of netting and allocation of collateral(e)(f)
(677) (1,261) (1,025) —
 (2,963) (677) (1,261) (1,025) —
 (2,963)
Commodity derivative assets subtotal(21)
402

726
 —

1,107

(21)
402

726
 —

1,107
(144)
281

948
 —

1,085

(144)
281

948
 —

1,085
Interest rate and foreign currency derivative assets                   
Total assets6,914

3,964

1,502

3,717

16,097

5,993

3,899

1,462

3,717

15,071
Liabilities                   
Commodity derivative liabilities                   
Economic hedges—
 4
 —
 —
 4
 —
 4
 —
 —
 4
(773) (1,695) (1,686) —
 (4,154) (773) (1,695) (1,406) —
 (3,874)
Effect of netting and allocation of collateral—
 (5) —
 —
 (5) —
 (5) —
 —
 (5)
Interest rate and foreign currency derivative assets subtotal—

(1)
—
 —

(1)
—

(1)
—
 —

(1)
Other investments—
 —
 42
 —
 42
 —
 —
 42
 —
 42
Total assets5,840

4,087

1,308

3,774

15,009

6,379

4,149

1,347

3,774

15,649
Proprietary trading—
 (59) (89) —
 (148) —
 (59) (89) —
 (148)
Effect of netting and allocation of collateral(e)(f)
770
 1,585
 1,329
 —
 3,684
 770
 1,585
 1,329
 —
 3,684
Commodity derivative liabilities subtotal(3) (169) (446) —
 (618) (3) (169) (166) —
 (338)
Deferred compensation obligation—
 (140) —
 —
 (140) —
 (37) —
 —
 (37)
Total liabilities(3)
(309)
(446) —

(758)
(3)
(206)
(166) —

(375)
Total net assets$6,911

$3,655

$1,056
 $3,717

$15,339

$5,990

$3,693

$1,296
 $3,717

$14,696


80
Table of Contents
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

 Generation Exelon
As of March 31, 2019Level 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(350) (2,339) (1,164) —
 (3,853) (350) (2,339) (1,404) —
 (4,093)
Proprietary trading—
 (79) (40) —
 (119) —
 (79) (40) —
 (119)
Effect of netting and allocation of collateral(f)(g)
346
 2,119
 977
 —
 3,442
 346
 2,119
 977
 —
 3,442

(4) (299) (227) —
 (530) (4) (299) (467) —
 (770)
Interest rate and foreign currency derivative liabilities                   
Derivatives designated as hedging instruments—
 —
 —
 —
 —
 —
 (2) —
 —
 (2)
Economic hedges—
 (12) —
 —
 (12) —
 (12) —
 —
 (12)
Effect of netting and allocation of collateral—
 5
 —
 —
 5
 —
 5
 —
 —
 5
Interest rate and foreign currency derivative liabilities subtotal—

(7)
—
 —

(7)
—

(9)
—
 —

(9)
Deferred compensation obligation—
 (36) —
 —
 (36) —
 (140) —
 —
 (140)
Total liabilities(4)
(342)
(227) —

(573)
(4)
(448)
(467) —

(919)
Total net assets$5,836

$3,745

$1,081
 $3,774

$14,436

$6,375

$3,701

$880
 $3,774

$14,730
 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


81
Table of Contents
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

 Generation Exelon
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)
$581
 $—
 $—
 $—
 $581
 $1,243
 $—
 $—
 $—
 $1,243
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 equivalents5
 —
 —
 —
 5
 48
 —
 —
 —
 48
Mutual funds24
 —
 —
 —
 24
 72
 —
 —
 —
 72
Fixed income—
 —
 —
 —
 —
 —
 15
 —
 —
 15
Life insurance contracts—
 22
 —
 —
 22
 —
 70
 38
 —
 108
Rabbi trust investments subtotal(e)
29

22

—
 —

51

120

85

38
 —

243
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(f)(g)
(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
Interest rate and foreign currency derivative assets        

         

Economic hedges—
 13
 —
 —
 13
 —
 13
 —
 —
 13
Effect of netting and allocation of collateral—
 (3) —
 —
 (3) —
 (3) —
 —
 (3)
Interest rate and foreign currency derivative assets subtotal—

10

—
 —

10

—

10

—
 —

10
Other investments—
 —
 42
 —
 42
 —
 —
 42
 —
 42
Total assets5,820

4,102

1,400

3,433

14,755

6,573

4,165

1,438

3,433

15,609

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

Generation ExelonExelon 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
TotalLevel 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) (1,027) —
 (4,632) (642) (2,963) (1,276) —
 (4,881)(642) (2,963) (1,276) —
 (4,881) (642) (2,963) (1,027) —
 (4,632)
Proprietary trading—
 (73) (21) —
 (94) —
 (73) (21) —
 (94)—
 (73) (21) —
 (94) —
 (73) (21) —
 (94)
Effect of netting and allocation of collateral(g)(f)
639
 2,581
 808
 —
 4,028
 639
 2,581
 808
 —
 4,028
639
 2,581
 808
 —
 4,028
 639
 2,581
 808
 —
 4,028
Commodity derivative liabilities subtotal(3)
(455)
(240) —

(698)
(3)
(455)
(489) —

(947)(3)
(455)
(489) —

(947)
(3)
(455)
(240) —

(698)
Interest rate and foreign currency derivative liabilities                   
Derivatives designated as hedging instruments—
 —
 —
 —
 —
 —
 (4) —
 —
 (4)
Economic hedges—
 (6) —
 —
 (6) —
 (6) —
 —
 (6)
Effect of netting and allocation of collateral—
 3
 —
 —
 3
 —
 3
 —
 —
 3
Interest rate and foreign currency derivative liabilities subtotal—

(3)
—
 —

(3)
—

(7)
—
 —

(7)
Deferred compensation obligation—
 (35) —
 —
 (35) —
 (137) —
 —
 (137)—
 (137) —
 —
 (137) —
 (35) —
 —
 (35)
Total liabilities(3)
(493)
(240) —

(736)
(3)
(599)
(489) —

(1,091)(3)
(592)
(489) —

(1,084)
(3)
(490)
(240) —

(733)
Total net assets$5,817

$3,609

$1,160
 $3,433

$14,019

$6,570

$3,566

$949
 $3,433

$14,518
$6,570

$3,563

$907
 $3,433

$14,473

$5,817

$3,602

$1,118
 $3,433

$13,970
_________
(a)GenerationExelon excludes cash of $270$347 million and $283$458 million at March 31,September 30, 2019 and December 31, 2018, respectively, and restricted cash of $36$112 million and $39$80 million at March 31, 2019 and December 31, 2018.  Exelon excludes cash of $426 million and $458 million at March 31,September 30, 2019 and December 31, 2018, and restricted cash of $71 million and $80 million at March 31, 2019 and December 31, 2018respectively, and includes long-term restricted cash of $211$186 million and $185 million at March 31,September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $183 million and $283 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $66 million and $39 million at September 30, 2019 and December 31, 2018, respectively. 
(b)Includes $43$85 million and $50 million of cash received from outstanding repurchase agreements at March 31,September 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 instrumentsliability of $7$2 million and a derivative asset of $44 million, which have a total notional amountamounts of $1,223$864 million and $1,432 million at March 31,September 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 $94$176 million and $130 million at March 31,September 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)The amount of unrealized gains/(losses) at Generation totaled less than $1 million for the three months ended March 31, 2019 and March 31, 2018, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million for the three months ended March 31, 2019 and March 31, 2018, respectively.
(f)Collateral posted/(received) from counterparties totaled $52$93 million, $283$324 million and $157$304 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31,September 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.
(g)(f)Of the collateral posted/(received), $(33)$306 million and $(94) million represents variation margin on the exchanges as of March 31,September 30, 2019 and December 31, 2018, respectively.
As of September 30, 2019, Exelon and Generation have outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $93 million, $241 million, $383 million, and $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 $71$75 million as of March 31,September 30, 2019. Changes were immaterial in fair value, cumulative adjustments and impairments for the three and nine months ended March 31,September 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.

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


ComEd, PECONote 9 — Fair Value of Financial Assets and BGE
The following tables present assets and liabilities measured and recorded at fair value in ComEd's, PECO's and BGE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2019 and December 31, 2018:
Liabilities
 ComEd PECO BGE
As of March 31, 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)
$194
 $—
 $—
 $194
 $16
 $—
 $—
 $16
 $3
 $—
 $—
 $3
Rabbi trust investments      
       
       
Mutual funds—
 —
 —
 —
 7
 —
 —
 7
 6
 —
 —
 6
Life insurance contracts—
 —
 —
 —
 —
 10
 —
 10
 —
 —
 —
 —
Rabbi trust investments subtotal(b)
—

—

—

—

7

10

—

17

6

—

—

6
Total assets194

—

—

194

23

10

—

33

9

—

—

9
Liabilities      
       
       
Deferred compensation obligation—
 (7) —
 (7) —
 (10) —
 (10) —
 (5) —
 (5)
Mark-to-market derivative liabilities(c)
—
 —
 (240) (240) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (7) (240) (247) —
 (10) —
 (10) —
 (5) —
 (5)
Total net assets (liabilities)$194
 $(7) $(240) $(53) $23
 $—
 $—
 $23
 $9
 $(5) $—
 $4

 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(b)
—

—

—

—

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(c)
—
 —
 (249) (249) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (6) (249) (255) —
 (10) —
 (10) —
 (5) —
 (5)
Total net assets (liabilities)$209
 $(6) $(249) $(46) $118
 $—
 $—
 $118
 $10
 $(5) $—
 $5
_________
(a)ComEd excludes cash of $69 million and $93 million at March 31, 2019 and December 31, 2018 and restricted cash of $15 million and $28 million at March 31, 2019 and December 31, 2018 and includes long-term restricted cash of $193 million and $166 million at March 31, 2019 and December 31, 2018, which is reported in Other deferred debits in the Consolidated Balance Sheets.  PECO excludes cash of $31 million and $24 million at March 31, 2019 and December 31, 2018.  BGE excludes cash of $12 million and $7 million at March 31, 2019 and December 31, 2018 and restricted cash of $1 million and $2 million at March 31, 2019 and December 31, 2018.
(b)The amount of unrealized gains/(losses) at ComEd, PECO and BGE totaled less than $1 million for the three months ended March 31, 2019 and March 31, 2018.
(c)The Level 3 balance consists of the current and noncurrent liability of $27 million and $213 million, respectively, at March 31, 2019, and $26 million and $223 million, respectively, at December 31, 2018, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

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

PHI, Pepco, DPL and ACE
The following tables present assets and liabilities measured and recorded at fair value in PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2019 and December 31, 2018:
  
 As of March 31, 2019 As of December 31, 2018
PHILevel 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets               
Cash equivalents(a)
$63
 $—
 $—
 $63
 $147
 $—
 $—
 $147
Rabbi trust investments      
       
Cash equivalents42
 —
 —
 42
 42
 —
 —
 42
Mutual funds14
 —
 —
 14
 13
 —
 —
 13
Fixed income—
 14
 —
 14
 —
 15
 —
 15
Life insurance contracts—
 22
 39
 61
 —
 22
 38
 60
Rabbi trust investments subtotal(b)
56

36

39

131

55

37

38

130
Total assets119

36

39

194
 202

37

38

277
Liabilities      
       
Deferred compensation obligation—
 (20) —
 (20) —
 (21) —
 (21)
Total liabilities—

(20)
—

(20)
—

(21)
—

(21)
Total net assets$119

$16

$39

$174
 $202

$16

$38

$256
 Pepco DPL ACE
As of March 31, 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)
$35
 $—
 $—
 $35
 $2
 $—
 $—
 $2
 $21
 $—
 $—
 $21
Rabbi trust investments                       
Cash equivalents42
 —
 —
 42
 —
 —
 —
 —
 —
 —
 —
 —
Fixed income—
 4
 —
 4
 —
 —
 —
 —
 —
 —
 —
 —
Life insurance contracts—
 22
 38
 60
 —
 —
 —
 —
 —
 —
 —
 —
Rabbi trust investments subtotal(b)
42

26

38

106

—

—

—

—

—

—

—

—
Total assets77

26

38

141

2

—

—

2

21

—

—

21
Liabilities
 
 
 

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

(3)
—

(3)
—

(1)
—

(1)
—

—

—

—
Total net assets (liabilities)$77
 $23
 $38
 $138
 $2
 $(1) $—
 $1
 $21
 $—
 $—
 $21

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


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 subtotal(b)
41

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 $29 million and $39 million at March 31, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $19 million at both March 31, 2019 and December 31, 2018, which is reported in Other deferred debits in the Consolidated Balance Sheets.  Pepco excludes cash of $11 million and $15 million at March 31, 2019 and December 31, 2018, respectively. DPL excludes cash of $6 million and $8 million at March 31, 2019 and December 31, 2018, respectively. ACE excludes cash of $7 million at both March 31, 2019 and December 31, 2018, and includes long-term restricted cash of $19 million at both March 31, 2019 and December 31, 2018, which is reported in Other deferred debits in the Consolidated Balance Sheets.
(b)The amount of unrealized gains/(losses) at PHI totaled less than $1 million for both the three months ended March 31, 2019 and 2018. The amount of unrealized gains/(losses) at Pepco totaled less than $1 million for both the three months ended March 31, 2019 and 2018.

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

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2019 and 2018:
 Generation ComEd PHI   Exelon
Three Months Ended March 31, 2019
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 
Other
Investments
 Total Generation 
Mark-to-Market
Derivatives
 
Life Insurance Contracts(c)
 Eliminated in Consolidation Total
Balance as of December 31, 2018$543
 $575
 $42
 $1,160
 $(249) $38
 $—
 $949
Total realized / unrealized gains (losses)      
       
Included in net income2
 (231)
(a) 
—
 (229) —
 1
 —
 (228)
Included in noncurrent payables to affiliates11
 —
 —
 11
 —
 —
 (11) —
Included in regulatory assets/liabilities—
 —
 —
 —
 9
(b) 
—
 11
 20
Change in collateral—
 81
 —
 81
 —
 —
 —
 81
Purchases, sales, issuances and settlements      
       

Purchases1
 57
 —
 58
 —
 —
 —
 58
Sales—
 —
 —
 —
 —
 —
 —
 —
Settlements(17) —
 —
 (17) —
 —
 —
 (17)
Transfers into Level 3—
 —
(d) 
—
 —
 —
 —
 —
 —
Transfers out of Level 3—
 17
(d) 
—
 17
 —
 —
 —
 17
Balance at March 31, 2019$540
 $499
 $42
 $1,081
 $(240) $39
 $—
 $880
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2019$2
 $(151) $—
 $(149) $—
 $1
 $—
 $(148)
 Generation ComEd PHI   Exelon
Three Months Ended March 31, 2018
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 
Other
Investments
 Total Generation 
Mark-to-Market
Derivatives
 
Life Insurance Contracts(c)
 Eliminated in Consolidation Total
Balance as of December 31, 2017$648
 $552
 $37
 $1,237
 $(256) $22
 $—
 $1,003
Total realized / unrealized gains (losses)      

        
Included in net income—
 184
(a) 
1
 185
 —
 1
 —
 186
Included in noncurrent payables to affiliates7
 —
 —
 7
 —
 —
 (7) —
Included in regulatory assets—
 —
 —
 —
 (11)
(b) 
—
 7
 (4)
Change in collateral—
 105
 —
 105
 —
 —
 —
 105
Purchases, sales, issuances and settlements      

       
Purchases2
 88
 —
 90
 —
 —
 —
 90
Sales—
 (3) —
 (3) —
 —
 —
 (3)
Issuances—
 —
 —
 —
 —
 —
 —
 —
Settlements(48) —
 —
 (48) —
 —
 —
 (48)
Transfers into Level 3—
 (8)
(d) 
—
 (8) —
 —
 —
 (8)
Transfers out of Level 3—
 —
(d) 
(2) (2) —
 —
 —
 (2)
Balance as of March 31, 2018$609

$918

$36

$1,563

$(267)
$23
 $—

$1,319
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2018$—
 $256
 $1
 $257
 $—
 $1
 $—
 $258

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 $80 million and $72 million of realized gains due to the settlement of derivative contracts for the three months ended March 31, 2019 and 2018, respectively.
(b)Includes $14 million of decreases in fair value and an increase for realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2019. Includes $17 million of increases in fair value and an increase for realized losses due to settlements of $6 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2018.
(c)The amounts represented are life insurance contracts at Pepco.
(d)Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.
The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2019 and 2018:
 Generation PHI Exelon
 Operating
Revenues		 Purchased
Power and
Fuel		 Other, net Operating and Maintenance Operating
Revenues		 Purchased
Power and
Fuel		 Operating and Maintenance Other, net
Total gains (losses) included in net income for the three months ended March 31, 2019$(128) $(103) $2
 $1
 $(128) $(103) $1
 $2
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2019(91) (60) 2
 1
 (91) (60) 1
 2
 Generation PHI Exelon
 
Operating
Revenues
 
Purchased
Power and
Fuel
 Other, net Operating and Maintenance 
Operating
Revenues
 
Purchased
Power and
Fuel
 Operating and Maintenance Other, net
Total gains (losses) included in net income for the three months ended March 31, 2018$335
 $(151) $1
 $1
 $335
 $(151) $1
 $1
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2018309
 (53) 1
 1
 309
 (53) 1
 1
Valuation Techniques Used to Determine Fair Value
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.
Cash Equivalents (All Registrants). The Registrants’ cash equivalents include investments with original maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.
NDT Fund Investments (Exelon and Generation). The trust fund investments have been established to satisfy Generation’s and CENG's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities and Fixed Income. Generation’s and CENG's NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.
With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds which are based on quoted prices in active markets

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

are categorized in Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.
For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities, which are included in Corporate debt, are determined using a third-party valuation that contains significant unobservable inputs and are categorized in Level 3.
Equity and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives such as holding short-term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For commingled funds and mutual funds, which are not publicly quoted, the funds are valued using NAV as a practical expedient for fair value which is primarily derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investmentscan typically can be redeemed monthly with 30 or less days of notice and without further restrictions.
Derivative instruments consisting primarily of futures and interest rate swaps to manage risk are recorded at fair value. Over the counter derivatives are valued daily based on quoted prices in active markets and trade in open markets and have been categorized as Level 1. Derivative instruments other than over the counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.
Middle For managed middle market lending are investments in loans or managed funds, which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in loans are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservablemodels and utilize complex valuation models. Managed funds are valued using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.
Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. The fair value of private equity and real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date.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.
AsComEd, PECO and BGE
 ComEd PECO BGE
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)
$264
 $—
 $—
 $264
 $207
 $—
 $—
 $207
 $122
 $—
 $—
 $122
Rabbi trust investments      
       
       
Mutual funds—
 —
 —
 —
 8
 —
 —
 8
 7
 —
 —
 7
Life insurance contracts—
 —
 —
 —
 —
 11
 —
 11
 —
 —
 —
 —
Rabbi trust investments subtotal—

—

—

—

8

11

—

19

7

—

—

7
Total assets264

—

—

264

215

11

—

226

129

—

—

129
Liabilities      
       
       
Deferred compensation obligation—
 (7) —
 (7) —
 (8) —
 (8) —
 (5) —
 (5)
Mark-to-market derivative liabilities(b)
—
 —
 (280) (280) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (7) (280) (287) —
 (8) —
 (8) —
 (5) —
 (5)
Total net assets (liabilities)$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

83
Table of March 31, 2019, Exelon and Generation have outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $127 million, $179 million, $301 million, and $268 million, respectively. These commitments will be funded by Generation’s existing NDT funds.Contents

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
Concentrations
_________
(a)ComEd excludes cash of $76 million and $93 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $31 million and $28 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $171 million and $166 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  PECO excludes cash of $23 million and $24 million at September 30, 2019 and December 31, 2018, respectively.  BGE excludes cash of $8 million and $7 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $1 million and $2 million at September 30, 2019 and December 31, 2018, respectively.
(b)The Level 3 balance consists of the current and noncurrent liability of $27 million and $253 million, respectively, at September 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 September 30, 2019 As of December 31, 2018
PHILevel 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets               
Cash equivalents(a)
$107
 $—
 $—
 $107
 $147
 $—
 $—
 $147
Rabbi trust investments      
       
Cash equivalents43
 —
 —
 43
 42
 —
 —
 42
Mutual funds13
 —
 —
 13
 13
 —
 —
 13
Fixed income—
 13
 —
 13
 —
 15
 —
 15
Life insurance contracts—
 24
 40
 64
 —
 22
 38
 60
Rabbi trust investments subtotal56

37

40

133

55

37

38

130
Total assets163

37

40

240
 202

37

38

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

(19)
—

(19)
—

(21)
—

(21)
Total net assets$163

$18

$40

$221
 $202

$16

$38

$256
 Pepco DPL ACE
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)
$34
 $—
 $—
 $34
 $—
 $—
 $—
 $—
 $18
 $—
 $—
 $18
Rabbi trust investments                       
Cash equivalents43
 —
 —
 43
 —
 —
 —
 —
 —
 —
 —
 —
Fixed income—
 3
 —
 3
 —
 —
 —
 —
 —
 —
 —
 —
Life insurance contracts—
 24
 40
 64
 —
 —
 —
 —
 —
 —
 —
 —
Rabbi trust investments subtotal43

27

40

110

—

—

—

—

—

—

—

—
Total assets77

27

40

144

—

—

—

—

18

—

—

18
Liabilities
 
 
 

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

(2)
—

(2)
—

—

—

—

—

—

—

—
Total net assets$77
 $25
 $40
 $142
 $—
 $—
 $—
 $—
 $18
 $—
 $—
 $18

84
Table of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of March 31, 2019. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of March 31, 2019, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.Contents
See Note 13 — Nuclear Decommissioning for additional information on the NDT fund investments.
Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, and Pepco). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and life insurance policies. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3.
Mark-to-Market Derivatives (Exelon, Generation, ComEd, PHI and DPL). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.
Exelon may utilize fixed-to-floating interest rate swaps as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 10 — Derivative Financial Instruments for additional information on mark-to-market derivatives.
Deferred Compensation Obligations (All Registrants). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

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 $45 million and $39 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $15 million and $19 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  Pepco excludes cash of $18 million and $15 million at September 30, 2019 and December 31, 2018, respectively. DPL excludes cash of $11 million and $8 million at September 30, 2019 and December 31, 2018, respectively. ACE excludes cash of $13 million and $7 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $15 million and $19 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in thefollowing tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 withinpresent the fair value hierarchy.
Additional Information Regardingreconciliation of Level 3 Fair Value Measurements (Exelon, Generation, ComEd, PHI, Pepco, DPLassets and ACE)
NDT Fund Investments (Exelon and Generation). For middle market lending and certain corporate debt securities investments, theliabilities measured at fair value is determined using a combination of valuation models including cost models, market models and income models. The valuation estimates are based on discounting the forecasted cash flows, market-based comparable data, credit and liquidity factors, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied for factors such as size, marketability, credit risk and relative performance.
Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Therefore, Generation has not disclosed such inputs.
Rabbi Trust Investments - Life insurance contracts (Exelon, PHI, and Pepco).For life insurance policies categorized as Level 3, the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such inputs.
Mark-to-Market Derivatives (Exelon, Generation and ComEd). For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.
Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements.
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a numberrecurring basis during the three and nine months ended September 30, 2019 and 2018:
 Exelon Generation ComEd PHI and Pepco  
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 income(171) 2
 (173)
(a) 
(171) —
 —
 —
Included in noncurrent payables to affiliates—
 11
 —
 11
 —
 —
 (11)
Included in regulatory assets/liabilities4
 —
 —
 —
 (7)
(b) 
—
 11
Change in collateral41
 —
 41
 41
 —
 —
 —
Purchases, sales, issuances and settlements

     
      
Purchases53
 1
 52
 53
 —
 —
 —
Sales(22) (21) (1) (22) —
 —
 —
Settlements(18) (18) —
 (18) —
 —
 —
Transfers into Level 31
 —
 1
(c) 
1
 —
 —
 —
Transfers out of Level 3(11) —
 (11)
(c) 
(11) —
 —
 —
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) $—
 $—
 $—

85
Table of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility isContents

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
generally shorter than
 Exelon Generation ComEd PHI and Pepco  
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
 $—
Total realized / unrealized gains (losses)

     

      
Included in net income(125) 5
 (132)
(a) 
(127) —
 2
 —
Included in noncurrent payables to affiliates—
 32
 —
 32
 —
 —
 (32)
Included in regulatory assets1
 —
 —
 —
 (31)
(b) 
—
 32
Change in collateral227
 —
 227
 227
 —
 —
 —
Purchases, sales, issuances and settlements

     

      
Purchases163
 43
 120
 163
 —
 —
 —
Sales(23) (21) (2) (23) —
 —
 —
Settlements(88) (88) —
 (88) —
 —
 —
Transfers into Level 35
 —
 5
(c) 
5
 —
 —
 —
Transfers out of Level 3(11) —
 (11)
(c) 
(11) —
 —
 —
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 $153 million and $298 million of realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2019, respectively.
(b)Includes $7 million of decreases in fair value and an increase for realized losses due to settlements of $4 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2019. Includes $31 million of decreases in fair value and an increase for realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 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.

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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  
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(259) (1) (259)
(a) 
(260) —
 1
 —
Included in noncurrent payables to affiliates—
 (4) —
 (4) —
 —
 4
Included in regulatory assets(11) —
 —
 —
 (7)
(b) 
—
 (4)
Change in collateral(44) —
 (44) (44) —
 —
 —
Purchases, sales, issuances and settlements
     

      
Purchases96
 15
 81
 96
 —
 —
 —
Settlements(29) (29) —
 (29) —
 —
 —
Transfers into Level 33
 —
 3
(c) 
3
 —
 —
 —
Transfers out of Level 3(6) —
 (6)
(c) 
(6) —
 —
 —
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  
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
 $—
Total realized / unrealized gains (losses)
     

      
Included in net income(186) (1) (188)
(a) 
(189) —
 3
 —
Included in regulatory assets(3) —
 —
 —
 (3)
(b) 
—
 —
Change in collateral14
 —
 14
 14
 —
 —
 —
Purchases, sales, issuances and settlements
     

      
Purchases215
 34
 181
 215
 —
 —
 —
Sales(3) —
 (3) (3) —
 —
 —
Settlements(103) (115) —
 (115) —
 12
 —
Transfers into Level 3(21) —
 (21)
(c) 
(21) —
 —
 —
Transfers out of Level 3(23) —
 (23)
(c) 
(23) —
 —
 —
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
 $—
 $—
 $—

__________
(a)Includes a reduction for the reclassification of $155 million and $347 million of realized losses due to the settlement of derivative contracts for the three and nine months ended September 30, 2018, respectively.
(b)
Includes $4 million of increases in fair value and an increase for realized losses due to settlements of $3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2018. Includes $9 million of decreases in fair value and an increase for realized losses due to settlements of $12 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2018.
(c)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.

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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 underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majorityincome statement classification of the instrument’s market price. As a result, the changetotal realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value is closely tied to liquid market movementson a recurring basis during the three and not a changenine months ended September 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 (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 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) —


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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 powermillions, except per share data, unless otherwise noted)

Note 9 — Fair Value of Financial Assets and gas delivery locations is approximately $2.52 and $0.46 for power and natural gas, respectively. Many of the commodity derivatives are short-term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.Liabilities
On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 10 —Derivative Financial Instruments for additional information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.
The table below discloses the significant inputs to the forward curve used to value these positions.
Type of trade 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)
 $411
 $443
 Discounted
Cash Flow		 Forward power
price		 $11-$167 $12-$174
  

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

   Option
Model		 Volatility
percentage		 9%-200% 10%-277%
                 
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
 $67
 $56
 Discounted
Cash Flow		 Forward power
price		 $17-$167 $14-$174
                 
Mark-to-market derivatives (Exelon and ComEd) $(280) $(249) Discounted
Cash Flow		 
Forward heat
rate(c)
 9x-10x 10x-11x
        Marketability
reserve		 4%-7% 4%-8%
        Renewable
factor		 87%-119% 86%-120%
Type of trade Fair Value at March 31, 2019 
Valuation
Technique
 
Unobservable
Input
 Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)
 $278
 Discounted
Cash Flow		 Forward power
price		 $9-$164
  

 
 Forward gas
price		 $1.76-$11.63
  

 Option Model Volatility
percentage		 10%-334%
           
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
 $64
 Discounted
Cash Flow		 Forward power
price		 $9-$162
           
Mark-to-market derivatives (Exelon and ComEd) $(240) Discounted
Cash Flow		 
Forward heat
rate(c)
 10x-11x
      Marketability
reserve		 4%-8%
      Renewable
factor		 85%-120%

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

Type of trade Fair Value at December 31, 2018 
Valuation
Technique
 
Unobservable
Input
 Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)
 $443
 Discounted
Cash Flow		 Forward power price $12-$174
    
 Forward gas price $0.78-$12.38
    Option Model Volatility percentage 10%-277%
           
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
 $56
 Discounted
Cash Flow		 Forward power price $14-$174
           
Mark-to-market derivatives (Exelon and ComEd) $(249) Discounted Cash Flow 
Forward heat
rate(c)
 10x-11x
      Marketability reserve 4%-8%
      Renewable factor 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 $157$304 million and $76 million as of March 31,September 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.

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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)
To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.
Derivative authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair valueGeneration. To the extent the amount of energy Generation produces differs from the derivative recognized in earnings immediately. Other accounting treatmentsamount of energy it has contracted to sell, Exelon and Generation are available through special election and designation, provided they meet specific, restrictive criteria

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

both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedges and fair value hedges. For Generation, all derivative economic hedges relatedexposed to commodities are recorded at fair value through earnings for the consolidated company, referred to as economic hedgesmarket fluctuations in the following tables. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portionprices of Generation’s overall energy marketing activities.
Fair value authoritative guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column. As of March 31, 2019, $6 million of cash collateral held, and as of December 31, 2018, $2 million of cash collateral posted and an additional $12 million of cash collateral posted with ComEd, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or had no positions to offset as of the balance sheet date. Excluded from the tables below are economic hedges that qualify for the NPNS scope exceptionelectricity, fossil fuels and other non-derivative contracts that are accounted for under the accrual method of accounting.
ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1).
Cash collateral held by PECO and BGE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

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

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of March 31, 2019:
  Generation ComEd Exelon
Derivatives 
Economic
Hedges
 
Proprietary
Trading
 
Collateral
and
Netting(a)(d)
 
Subtotal(b)
 
Economic
Hedges(c)
 
Total
Derivatives
Mark-to-market derivative assets
(current assets)
 $2,691
 $118
 $(2,156) $653
 $—
 $653
Mark-to-market derivative assets
(noncurrent assets)
 1,188
 60
 (794) 454
 —
 454
Total mark-to-market derivative assets 3,879
 178
 (2,950) 1,107
 —
 1,107
Mark-to-market derivative liabilities
(current liabilities)
 (2,711) (89) 2,485
 (315) (27) (342)
Mark-to-market derivative liabilities
(noncurrent liabilities)
 (1,142) (30) 957
 (215) (213) (428)
Total mark-to-market derivative liabilities (3,853) (119) 3,442
 (530) (240) (770)
Total mark-to-market derivative net assets (liabilities) $26
 $59
 $492
 $577
 $(240) $337
_________
(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 are not reflected in the table above.
(b)Current and noncurrent assets are shown net of collateral of $152 million and $63 million, respectively, and current and noncurrent liabilities are shown net of collateral of $177 million and $100 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $492 million at March 31, 2019.
(c)Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(d)Of the collateral posted/(received), $(33) million represents variation margin on the exchanges.

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

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2018:
  Generation ComEd Exelon
Description Economic
Hedges		 Proprietary
Trading		 
Collateral
and
Netting(a)(d)
 
Subtotal(b)
 
Economic
Hedges(c)
 Total
Derivatives
Mark-to-market derivative assets
(current assets)		 $3,505
 $105
 $(2,809) $801
 $—
 $801
Mark-to-market derivative assets
(noncurrent assets)		 1,266
 41
 (862) 445
 —
 445
Total mark-to-market derivative assets 4,771
 146
 (3,671) 1,246
 —
 1,246
Mark-to-market derivative liabilities
(current liabilities)		 (3,429) (74) 3,056
 (447) (26) (473)
Mark-to-market derivative liabilities
(noncurrent liabilities)		 (1,203) (20) 972
 (251) (223) (474)
Total mark-to-market derivative liabilities (4,632) (94) 4,028
 (698) (249) (947)
Total mark-to-market derivative net assets (liabilities) $139
 $52
 $357
 $548
 $(249) $299
_________ 
(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, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
(b)Current and noncurrent assets are shown net of collateral of $121 million and $51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $125 million and $60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $357 million at December 31, 2018.
(c)Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(d)Of the collateral posted/(received), $(94) million represents variation margin on the exchanges.
Economic Hedges (Commodity Price Risk)
commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.

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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.
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 September 30, 2019 and December 31, 2018 and is not presented in the fair value tables below.

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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 and ComEd as of September 30, 2019 and December 31, 2018:
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)
 $602
 $2,452
 $143
 $212
 $(2,205) $602
 $—
Mark-to-market derivative assets
(noncurrent assets)
 483
 1,386
 67
 104
 (1,074) 483
 —
Total mark-to-market derivative assets 1,085
 3,838
 210
 316
 (3,279) 1,085
 —
Mark-to-market derivative liabilities
(current liabilities)
 (224) (2,550) (101) 249
 2,205
 (197) (27)
Mark-to-market derivative liabilities
(noncurrent liabilities)
 (394) (1,324) (47) 156
 1,074
 (141) (253)
Total mark-to-market derivative liabilities (618) (3,874) (148) 405
 3,279
 (338) (280)
Total mark-to-market derivative net assets (liabilities) $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), $306 million and $(94) million represents variation margin on the exchanges at September 30, 2019 and December 31, 2018 respectively.

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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 nine months ended March 31,September 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 "NetNet fair value changes related to derivatives"derivatives line in the Consolidated Statements of Cash Flows.
  Three Months Ended
September 30,		 Nine Months Ended
September 30,
  2019 2018 2019 2018
Income Statement Location Gain (Loss) Gain (Loss)
Operating revenues $76
 $8
 $65
 $(99)
Purchased power and fuel (45) 66
 (127) (4)
Total Exelon and Generation $31
 $74
 $(62) $(103)
  Three Months Ended
March 31,
  2019 2018
Income Statement Location Gain (Loss)
Operating revenues $(50) $(100)
Purchased power and fuel 30
 (167)
Total Exelon and Generation $(20) $(267)

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


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 March 31,September 30, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 90%-93%96%-99%, 64%-67%84%-87% and 38%-41%54%-57% for 2019, 2020 and 2021, respectively.
On December 17, 2010, ComEd executed several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts in its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information.
PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2018 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2018 and previous PGC settlements, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 20% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s results of operations and financial position as natural gas costs are fully recovered from customers under the PGC.
BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE's wholesale power supply costs and include an administrative fee. BGE’s commodity price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.
BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery.
Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco's wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s commodity price risk related to electric supply procurement is limited. Pepco locks in fixed prices for its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.
DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The SOS rates charged recover DPL's wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin (RARM). The RARM includes

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

a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. In Maryland, DPL charges an administrative fee intended to allow it to recover its administrative costs. DPL locks in fixed prices for its SOS requirements through full requirements contracts. DPL’s commodity price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.
DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up against forecasts on a monthly basis and any shortfall or excess is carried forward as a recovery balance in the next GCR filing. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage, a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas. The hedge program requires that DPL hedge, on a non-discretionary basis, an amount equal to 50% of estimated purchase requirements for each month, including estimated monthly purchases for storage injections. The 50% hedge monthly target is achieved by hedging 1/12th of the 50% target each month beginning 12-months prior to the month in which the physical gas is to be purchased. Currently, DPL uses only exchange traded futures for its gas hedging program, which are considered derivatives, however, it retains the capability to employ other physical and financial hedges if needed. DPL has not elected hedge accounting for these derivative financial instruments. Because of the DPSC-approved fuel adjustment clause for DPL's derivatives, the change in fair value of the derivatives each period, in addition to all premiums paid and other transaction costs incurred as part of the gas hedging program, are fully recoverable and are recorded by DPL as regulatory assets or liabilities. DPL’s physical gas purchases are currently all daily, monthly or intra-month transactions. From time to time, DPL will enter into seasonal purchase or sale arrangements, however, there are none currently in the portfolio. Certain of DPL's full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.
ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE's wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s commodity price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS requirements through full requirements contracts. Certain of ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.
Proprietary Trading (Commodity Price Risk)
Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon's RMC monitor the financial risks of the proprietary trading activities. The proprietary trading activities are a complement to Generation's energy marketing portfolio but represent a small portion of Generation's overall revenue from energy marketing activities. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.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 nine months ended March 31,September 30, 2019 and 2018, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also included in the "Net fair value changes related to derivatives" in the Consolidated Statements of Cash Flows.for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.
  Three Months Ended
March 31,
  2019 2018
Income Statement Location Gain (Loss)
Operating revenues $2
 $2

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

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 $1,419$1,371 million and $1,420 million at March 31,September 30, 2019 and December 31, 2018, respectively, for Exelon and $619$571 million and $620 million at March 31,September 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 $209$257 million and $268 million at March 31,September 30, 2019 and December 31, 2018, respectively.
The mark-to-market derivative assets and liabilities as of March 31,September 30, 2019 and December 31, 2018 and the mark-to-market gains and losses for the three and nine months ended March 31,September 30, 2019 and 2018 were not material for Exelon and Generation.
Credit Risk Collateral and Contingent-Related Features (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date.
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

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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.

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

The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of March 31,September 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 $36$68 million, $31$30 million, $27$32 million, $37$39 million, $5$15 million and $4$8 million as of March 31,September 30, 2019, respectively. 
Rating as of March 31, 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$819
 $11
 $808
 1
 $135
$693
 $10
 $683
 —
 $—
Non-investment grade86
 39
 47
 

 

74
 38
 36
 


 


No external ratings                  
Internally rated — investment grade162
 —
 162
 

 

297
 1
 296
 


 


Internally rated — non-investment grade87
 7
 80
 

 

175
 24
 151
 


 


Total$1,154
 $57
 $1,097
 1
 $135
$1,239
 $73
 $1,166
 —
 $—
Net Credit Exposure by Type of Counterparty As of
March 31, 2019		 As of
September 30, 2019
Financial institutions $13
 $1
Investor-owned utilities, marketers, power producers 762
 875
Energy cooperatives and municipalities 287
 255
Other 35
 35
Total $1,097
 $1,166
_________ 
(a)As of March 31,September 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $37$18 million of cash and $19$55 million of letters of credit. The credit collateral does not include non-liquid collateral.
ComEd’s power procurementUtility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. The credit position is based on daily, updated forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energyexposure on the supply contract exceeds the benchmark price on a given day,amount of unsecured credit, the suppliers aremay be required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract.collateral. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of March 31, 2019, ComEd’s net credit exposure to suppliers was $2 million.
ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated primarily by itsthe ability to recover realized energyprocurement costs through customer rates. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information.
PECO’s unsecured credit used by the suppliers represents PECO’s net credit exposure. As of March 31,September 30, 2019, PECO had no material net credit exposure to its electric suppliers.
PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’sUtility Registrants’ counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. As of March 31, 2019, PECO had no material credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.

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

BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information.
BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. As of March 31, 2019, BGE's net credit exposure to suppliers was immaterial.
BGE’s regulated gas business is exposed to market-price risk. At March 31, 2019, BGE's credit exposure related to off-system sales, which is mitigated by parental guarantees, letters of credit or right to offset clauses within other contracts with those third-party suppliers, was immaterial.
Pepco’s, DPL's and ACE's power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL's and ACE's net credit exposure. As of March 31, 2019, Pepco’s, DPL's and ACE's net credit exposures to suppliers were immaterial.
Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL's and ACE's counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 2 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information.
DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually to reflect realized natural gas prices. To the extent that the fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder. As of March 31, 2019, DPL's credit exposure under its natural gas supply and asset management agreements with investment grade suppliers was immaterial.
CollateralCredit-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

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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 margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk relatedcredit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.

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

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 March 31, 2019 December 31, 2018 September 30, 2019 December 31, 2018
Gross fair value of derivative contracts containing this feature(a)
 $(1,667) $(1,723) $(1,249) $(1,723)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)
 1,177
 1,105
 947
 1,105
Net fair value of derivative contracts containing this feature(c)
 $(490) $(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.
Generation had cash collateral postedAs of $542 million and letters of credit posted of $289 million and cash collateral held of $56 million and letters of credit held of $26 million as of March 31, 2019 for external counterparties with derivative positions. Generation had cash collateral posted of $418 million and letters of credit posted of $367 million and cash collateral held of $47 million and letters of credit held of $44 million at December 31, 2018 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e., to BB+ by S&P or Ba1 by Moody’s), Generation would have been required to post additional collateral of $1.9 billion and $2.1 billion as of March 31,September 30, 2019 and December 31, 2018, respectively. TheseExelon and Generation posted or held the following amounts represent the potential additionalof cash collateral requiredand letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
Exelon's interest rate swaps contain provisions that, in the event of a merger, if Exelon’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of March 31, 2019, Exelon's swaps were in a liability position that is not material.
  September 30, 2019 December 31, 2018
Cash collateral posted $787
 $418
Letters of credit posted 273
 367
Cash collateral held 96
 47
Letters of credit held 58
 44
Additional collateral required in the event of a credit downgrade below investment grade 1,481
 2,104
See Note 24 — Segment Information of the Exelon 2018 Form 10-K for additional information regarding the letters of credit supporting the cash collateral.
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd’s standard block energy
Utility Registrants
The Utility Registrants’ electric supply procurement contracts collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of March 31, 2019, ComEd held $11 million in collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's REC and ZEC contracts, collateral postings are required to cover a percentage of the REC and ZEC contract value. As of March 31, 2019, ComEd held $31 million in collateral from suppliers for REC and ZEC contract obligations. Under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of March 31, 2019, ComEd held $19 million in collateral from suppliers for the long-term renewable energy contracts. If ComEd lost its investment grade credit rating as of March 31, 2019, it would have been required to post approximately $8 million of collateral to its counterparties. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information.
PECO’s natural gas procurement contractsdo not contain provisions that couldwould require PECOthem to post collateral. This collateral may be posted in the form

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Table of cash or credit support with thresholds contingent upon PECO’s credit ratingContents

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


Note 10 — Derivative Financial Instruments
from
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 major credit rating agencies. The collateral andform of cash or credit support, requirementswhich vary by contract and by counterparty.counterparty, with thresholds contingent upon PECO’s, BGE, and DPL’s credit rating. As of March 31,September 30, 2019, PECO, wasBGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE or DPL lost itstheir investment grade credit ratingratings as of March 31,September 30, 2019, PECOthey could have been required to post $34 million ofincremental collateral to its counterparties.
PECO’s supplier master agreements that govern the termscounterparties of its DSP Program contracts do not contain provisions that would require PECO to post collateral.
BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral$28 million, $26 million and credit support requirements vary by contract and by counterparty. As of March 31, 2019, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of March 31, 2019, BGE could have been required to post $46$11 million, of collateral to its counterparties.
DPL's natural gas procurement contracts contain provisions that could require DPL to post collateral. To the extent that the fair value of the natural gas derivative transaction in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The DPL obligations are standalone, without the guaranty of PHI. If DPL lost its investment grade credit rating as of March 31, 2019, DPL could have been required to post an additional amount of $14 million of collateral to its counterparties.
BGE's, Pepco's, DPL's and ACE's full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE, Pepco, DPL or ACE to post collateral.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 March 31,September 30, 2019 and December 31, 2018. Generation and PECO had no commercial paper borrowings as of both March 31,September 30, 2019 and December 31, 2018.
 Outstanding Commercial
Paper as of		 Average Interest Rate on
Commercial Paper Borrowings as of
Commercial Paper IssuerSeptember 30, 2019 December 31, 2018 September 30, 2019 December 31, 2018
Exelon$519
 $89
 2.50% 2.15%
ComEd387
 —
 2.51% 2.14%
BGE—
 35
 2.49% 2.18%
PHI132
 54
 2.52% 2.15%
PEPCO12
 40
 2.61% 2.24%
DPL57
 —
 2.42% 2.07%
ACE63
 14
 2.57% 2.21%

 Outstanding
Commercial
Paper at		 Average Interest Rate on
Commercial Paper Borrowings as of
Commercial Paper IssuerMarch 31, 2019 December 31, 2018 March 31, 2019 December 31, 2018
Exelon$629
 $89
 2.63% 2.15%
ComEd322
 —
 2.64% 2.14%
BGE106
 35
 2.59% 2.18%
PHI201
 54
 2.62% 2.15%
PEPCO105
 40
 2.62% 2.24%
DPL5
 —
 2.61% 2.07%
ACE91
 14
 2.62% 2.21%
See Note 13— Debt and Credit Agreements of the Exelon 2018 Form 10-K for additional information on the Registrants’ credit facilities.

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

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.

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Note 11 — Debt and Credit Agreements

Long-Term Debt
Issuance of Long-Term Debt
During the threenine months ended March 31,September 30, 2019, the following long-term debt was issued:
Company Type Interest Rate Maturity Amount Use of Proceeds
Generation 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.
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.
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
Pepco 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
ACE First Mortgage Bonds 4.14% May 21, 2049 $50
 Repay existing indebtedness and for general corporate purposes
Company 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.
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.

Debt Covenants
As of March 31,September 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 March 31,September 30, 2019, $502approximately $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 Pacific Gas and Electric Company (PG&E)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 March 31,September 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

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(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 March 31,September 30, 2019, $834$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 March 31, 2019
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit3.9 3.1 8.2 1.0 6.3 4.7 2.1 6.5 6.7
Qualified NDT fund income7.2 14.2 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.5) (0.9) (0.2) — (0.1) (0.2) (0.1) (0.2) (0.3)
Plant basis differences(1.4) — (0.5) (6.7) (0.9) (1.7) (2.0) (0.7) (2.3)
Production tax credits and other credits(0.8) (1.5) — — — — — — —
Noncontrolling interests(0.6) (1.1) — — — — — — —
Excess deferred tax amortization(4.7) — (8.5) (2.5) (7.9) (19.4) (17.9) (15.6) (23.9)
Other0.1 (0.5) 0.3 0.2 — (0.3) 0.4 0.7 (1.2)
Effective income tax rate24.2% 34.3% 20.3% 13.0% 18.4% 4.1% 3.5% 11.7% —%

 Three Months Ended September 30, 2019
 Exelon
Generation
ComEd
PECO
BGE PHI Pepco DPL ACE
U.S. Federal statutory rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit6.4 5.2 8.1 (0.3) 6.3 4.8 1.9 6.6 6.9
Qualified NDT fund income3.2 7.1 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(4.1) (8.9) (0.2) — (0.1) (0.2) (0.1) (0.2) (0.3)
Plant basis differences(1.7) — (1.0) (7.5) (1.1) (1.8) (2.6) (0.6) (1.9)
Production tax credits and other credits(1.2) (2.7) — — — — — — —
Noncontrolling interests(2.2) (4.8) — — — — — — —
Excess deferred tax amortization(6.5) — (9.9) (3.6) (8.0) (17.7) (16.3) (13.5) (23.3)
Other0.7 0.5 0.4 (0.5) (0.2) 0.8 1.0 (0.1) 0.7
Effective income tax rate15.6% 17.4% 18.4% 9.1% 17.9% 6.9% 4.9% 13.2% 3.1%

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


Note 12 — Income Taxes

 Three Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit(1.2) (9.0) 8.3 (3.6) 7.3 0.2 1.0 6.6 7.3
Qualified NDT fund income2.4 5.8 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.6) (1.1) (0.2) (0.1) — (0.2) (0.1) (0.3) (0.3)
Plant basis differences(2.5) — (0.3) (15.2) (0.8) (2.0) (3.4) (0.7) (1.3)
Production tax credits and other credits(1.2) (2.9) (0.1) — — — — — —
Noncontrolling interests(1.1) (2.8) — — — — — — —
Excess deferred tax amortization(6.8) — (7.8) (4.6) (7.9) (17.7) (21.2) (14.0) (15.4)
Tax Cuts and Jobs Act of 20171.3 3.5 — — — 0.2 0.1 — —
Other3.2 5.6 0.3 0.9 2.6 0.6 0.3 0.6 0.3
Effective income tax rate14.5% 20.1% 21.2% (1.6)% 22.2% 2.1% (2.3)% 13.2% 11.6%
  
 Nine Months Ended September 30, 2019
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit5.1 4.2 8.2 — 6.4 4.8 2.0 6.7 6.9
Qualified NDT fund income5.3 11.9 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(1.9) (4.0) (0.2) — (0.1) (0.2) (0.1) (0.2) (0.3)
Plant basis differences(1.6) — (0.7) (6.8) (1.1) (1.8) (2.3) (0.6) (2.0)
Production tax credits and other credits(1.0) (2.1) — — — — — — —
Noncontrolling interests(1.0) (2.3) — — — — — — —
Excess deferred tax amortization(6.0) — (9.2) (2.9) (7.9) (18.6) (17.3) (15.0) (23.4)
Other0.8 (0.1) 0.2 (0.2) 0.1 0.5 0.7 0.2 —
Effective income tax rate20.7% 28.6% 19.3% 11.1% 18.4% 5.7% 4.0% 12.1% 2.2%
 Three Months Ended March 31, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit4.1 2.4 8.2 (3.9) 6.3 4.6 1.7 6.3 6.6
Qualified NDT fund income(0.4) (1.3) — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(1.3) (4.3) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.3)
Plant basis differences(2.7) — 0.1 (14.2) (0.7) (2.6) (3.4) (1.3) (2.6)
Production tax credits and other credits(2.8) (9.5) (0.1) — — — — — —
Noncontrolling interests(0.7) (2.5) — — — — — — —
Excess deferred tax amortization(6.0) — (7.5) (4.8) (8.6) (10.6) (12.8) (7.9) (8.7)
Other(2.8) (1.3) 0.3 0.2 — — (0.3) 0.5 (3.5)
Effective income tax rate8.4% 4.5% 21.8% (1.8)% 17.9% 12.2% 6.1% 18.4% 12.5%

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

Note 12 — Income Taxes

 Nine Months Ended September 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit1.7 (2.6) 8.2 (3.6) 6.6 2.7 2.4 6.5 7.3
Qualified NDT fund income0.9 2.6 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.9) (2.2) (0.2) (0.1) (0.1) (0.2) (0.1) (0.3) (0.3)
Plant basis differences(2.7) — (0.1) (15.4) (0.7) (1.9) (2.9) (0.7) (1.3)
Production tax credits and other credits(1.8) (5.1) (0.1) — — — — — —
Noncontrolling interests(1.1) (3.2) — — — — — — —
Excess deferred tax amortization(6.1) — (7.6) (3.4) (8.1) (14.5) (16.5) (11.0) (14.0)
Tax Cuts and Jobs Act of 20170.2 1.3 (0.2) — — 0.3 — — —
Other0.4 2.0 0.1 — 0.9 0.3 — 0.4 0.9
Effective income tax rate11.6% 13.8% 21.1% (1.5)% 19.6% 7.7% 3.9% 15.9% 13.6%

Accounting for Uncertainty in Income Taxes
The RegistrantsExelon, Generation, ComEd, PHI and ACE have the following unrecognized tax benefits as of March 31,September 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 ACE
March 31, 2019$448
 $411
 $—
 $—
 $—
 $45
 $—
 $—
 $14
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
December 31, 2018$477
 $408
 $2
 $—
 $—
 $45
 $—
 $—
 $14
 Exelon Generation ComEd PHI ACE
September 30, 2019$448
 $411
 $—
 $45
 $14
December 31, 2018$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.

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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 March 31, 2019, Exelon, Generation, PHI and ACE have approximately $425 million, $411 million, $14 million and $14 million 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. Of the above unrecognized tax benefits, Exelon and Generation have $411 million that, if recognized, wouldcases as of September 30, 2019:

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

Exelon(a)

Generation(a)

PHI(b)

ACE(b)
$425

$411

$14

$14
decrease the effective tax rate. The unrecognized tax benefits__________
(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 regulated 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 third quarter of 2019, Exelon reviewed and updated its marginal state income tax rates based on 2018 state apportionment rates. As a result of the rate 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

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.

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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 March 31,September 30, 2019:
Nuclear decommissioning ARO at December 31, 2018 (a)(b)
$10,005
$10,005
Sale of Oyster Creek(755)
Accretion expense361
Net increase due to changes in, and timing of, estimated future cash flows223
211
Accretion expense120
Costs incurred related to decommissioning plants(19)(52)
Nuclear decommissioning ARO at March 31, 2019 (a)(b)
$10,329
Nuclear decommissioning ARO at September 30, 2019 (a)
$9,770
_________
(a)Includes $41$127 million and $22 million as the current portion of the ARO at March 31,September 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 $760 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 March 31, 2019 and December 31, 2018, respectively.2018. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.
During the threenine months ended March 31,September 30, 2019, Exelon's and Generation’s total nuclear ARO increaseddecreased by approximately $324$235 million, primarily reflecting the impactssale of ARO updates completed during first quarter 2019 andOyster Creek, partially offset by the accretion of the ARO liability due to the passage of time. time and the net impacts of ARO updates completed during the first and 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 $13,345$12,862 million and $12,695 million at March 31,September 30, 2019 and December 31, 2018, respectively. The NDT funds include $881 million andincluded $890 million at March 31, 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 announced pending sale of Oyster Creek. The NDT funds also include $163$156 million and $144 million for the current portion of the NDT funds at March 31,September 30, 2019 and December 31, 2018, respectively, which are 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.

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

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

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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 nine months ended March 31,September 30, 2019 and 2018.
 Pension Benefits
Three Months Ended September 30,		 OPEB
Three Months Ended September 30,
 2019 2018 2019 2018
Components of net periodic benefit cost:       
Service cost$89
 $100
 $23
 $28
Interest cost221
 201
 47
 43
Expected return on assets(306) (312) (38) (43)
Amortization of:       
Prior service benefit—
 —
 (45) (47)
Actuarial loss104
 158
 11
 18
Settlement charges7
 —
 —
 —
Contractual termination benefits1
 —
 —
 —
Net periodic benefit cost$116
 $147
 $(2) $(1)


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

Note 14 — Retirement Benefits
 Pension Benefits
Three Months Ended March 31,		 Other Postretirement Benefits
Three Months Ended March 31,
 2019 2018 2019 2018
Components of net periodic benefit cost:       
Service cost$89
 $101
 $24
 $28
Interest cost221
 201
 47
 43
Expected return on assets(307) (312) (38) (43)
Amortization of:       
Prior service cost (benefit)—
 —
 (45) (46)
Actuarial loss104
 157
 11
 16
Net periodic benefit cost$107
 $147
 $(1) $(2)


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 months ended March 31, 2019 and 2018, while the non-service cost components are included in Other, net and Regulatory assets forassets. For Generation and the three months ended March 31, 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 months ended March 31, 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


104
  Three Months Ended
March 31,
Pension and Other Postretirement Benefit Costs 2019 2018
Exelon $106
 $145
Generation 31
 51
ComEd 24
 45
PECO 2
 5
BGE 16
 15
PHI 23
 15
Pepco 6
 4
DPL 4
 —
ACE 4
 3
Table of Contents

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


Note 14 — Retirement Benefits

Defined Contribution Savings Plans
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three and nine months ended March 31,September 30, 2019 and 2018, respectively.
  Three Months Ended September 30, Nine Months Ended September 30,
Savings Plan Matching Contributions 2019 2018 2019 2018
Exelon $36
 $44

$101

$126
Generation 14
 23
 41
 65
ComEd 9
 8
 26
 23
PECO 2
 2
 7
 7
BGE 4
 2
 9
 5
PHI 4
 4
 8
 10
Pepco 1
 1
 2
 2
DPL 1
 1
 2
 2
ACE 1
 1
 1
 2
  Three Months Ended
March 31,
Savings Plan Matching Contributions 2019 2018
Exelon $31

$32
Generation 13
 15
ComEd 7
 7
PECO 2
 2
BGE 2
 2
PHI 4
 3
Pepco 1
 1
DPL 1
 1
ACE 1
 —

15. Changes in Accumulated Other Comprehensive Income (Exelon and Generation)(Exelon)
The following tables present changes in accumulated other comprehensive income (loss) (AOCI)Exelon's AOCI, net of tax, by component for the three months ended March 31, 2019 and 2018:component:
Three Months Ended March 31, 2019Gains (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$(2) $—
 $(2,960) $(33) $—
 $(2,995)
OCI before reclassifications—
 —
 (38) 2
 (1) (37)
Amounts reclassified from AOCI(b)
—
 —
 20
 —
 —
 20
Net current-period OCI—
 —
 (18) 2
 (1) (17)
Ending balance$(2) $—
 $(2,978) $(31) $(1) $(3,012)
Generation(a)
          

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$(4) $—
 $—
 $(33) $(1) $(38)$(2) $(2,957) $(29) $(2) $(2,990)
OCI before reclassifications—
 —
 —
 2
 (1) 1
—
 6
 (2) —
 4
Amounts reclassified from AOCI1
 —
 —
 —
 —
 1
—
 21
 —
 2
 23
Net current-period OCI1
 —
 —
 2
 (1) 2
—
 27
 (2) 2
 27
Ending balance$(3) $—
 $—
 $(31) $(2) $(36)$(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)

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


Note 15 — Changes in Accumulated Other Comprehensive Income

Three Months Ended March 31, 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) $(3,026)
OCI before reclassifications8
 —
 18
 1
 —
 27
Amounts reclassified from AOCI(b)
—
 —
 44
 —
 —
 44
Net current-period OCI8
 —
 62
 1
 —
 71
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)
—
 (10) —
 —
 —
 (10)
Ending balance$(6) $—
 $(2,936) $(22) $(1) $(2,965)
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) $—
 $(2,995)
OCI before reclassifications7
 —
 —
 (1) —
 6
—
 (32) 2
 (2) (32)
Amounts reclassified from AOCI—
 —
 —
 —
 —
 —
—
 62
 —
 2
 64
Net current-period OCI7
 —
 —
 (1) —
 6
—
 30
 2
 —
 32
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)
—
 (3) —
 —
 —
 (3)
Ending balance$(9) $—
 $—
 $(24) $(1) $(34)$(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)

Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the three months ended March 31, 2019 and 2018. The following tables present amounts reclassified out of AOCI to Net income for Exelon during the three months ended March 31, 2019 and 2018.
Three Months Ended March 31, 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
     
Total Reclassifications $(20) Net of tax
Three Months Ended March 31, 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
     
Total Reclassifications $(44) 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.

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

The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss) during the three months ended March 31, 2019 and 2018::
 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)
 Three Months Ended
March 31,
 2019 2018
Exelon   
Pension and non-pension postretirement benefit plans:   
Prior service benefit reclassified to periodic benefit cost$6
 $6
Actuarial loss reclassified to periodic benefit cost(13) (22)
Pension and non-pension postretirement benefit plans valuation adjustment14
 (7)
Change in unrealized loss on cash flow hedges—
 (3)
Change in unrealized loss on investments in unconsolidated affiliates—
 (1)
Total$7
 $(27)
    
Generation   
Change in unrealized gain (loss) on cash flow hedges$1
 $(3)
Change in unrealized loss on investments in unconsolidated affiliates—
 (1)
Total$1
 $(4)

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 generation and other required commitments. In addition, the orders approving the merger in Delaware, New Jersey, and Maryland include a “most favored nation” provision which, generally, requires allocation of merger benefits proportionally across all the jurisdictions.
The following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the acquisition date and the remaining obligations as of March 31, 2019:
106
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  $123
 $90
 $71
 $12
 $7
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)


Note 16 — Commitments and Contingencies

Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL and ACE as of September 30, 2019:
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, will beare recognized as incurred and recorded in Exelon's and Generation's financial statements. As of March 31,September 30, 2019, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $97$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, DPL
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(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 March 31,September 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 $1,480
 $1,455
 $6
 $—
 $2
 $8
 $8
 $—
 $—
$1,718
 $1,192
 $515
 $11
 $—
 $—
 $—
Surety bonds(a)
 1,597
 1,376
 51
 9
 17
 40
 32
 5
 3
991
 315
 638
 38
 —
 —
 —
Financing trust guarantees 378
 —
 200
 178
 —
 —
 —
 —
 —
378
 —
 —
 —
 —
 —
 378
Guaranteed lease residual values(b)
 26
 —
 —
 —
 —
 26
 8
 11
 7
26
 —
 2
 3
 4
 3
 15
Total commercial commitments $3,481
 $2,831
 $257
 $187
 $19

$74
 $48
 $16
 $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

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(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 maximum lease term associated with these assets ranges from 31 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $68 million $22 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. The minimum lease term associated with these assets ranges from 1 to 4 years.Pepco, DPL and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Nuclear Insurance (Exelon and Generation). Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.
The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of March 31, 2019, the current liability limit per incident is $14.1 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. 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 $13.6 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $3.1 billion, however any amounts payable under this secondary layer would be capped at $454 million per year.

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

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $14.1 billion limit for a single incident.
As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 2 — Variable Interest Entities 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 $335 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.
NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by Exelon will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.
For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and 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.

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

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.

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

Note 16 — Commitments and Contingencies

As of March 31,September 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:
March 31, 2019
Total environmental
investigation and
remediation reserve
 
Portion of total related to
MGP investigation and
remediation
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$486

$347
$507

$346
 $496

$356
Generation108
 —
107
 —
 108
 —
ComEd320
 318
328
 327
 329
 327
PECO27
 25
20
 18
 27
 25
BGE5
 4
3
 1
 5
 4
PHI26

—
49

—
 27

—
Pepco24
 —
47
 —
 25
 —
DPL1
 —
1
 —
 1
 —
ACE1
 —
1
 —
 1
 —

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

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
 —
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 are negotiatinghave entered into a Consent AgreementsAgreement to design and implementperform the ROD remedy, and negotiations areRemedial Design, which is expected to be completed in the first quarter2020 - 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 2020.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 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

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(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.

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

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 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-

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

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

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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.
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 March 31,September 30, 2019 and December 31, 2018, Exelon and Generation had recorded estimated liabilities of approximately $77$83 million and $79 million, respectively, in total for asbestos-related bodily injury claims. As of March 31,September 30, 2019, approximately $25 million of this amount related to 239257 open claims presented to Generation, while the remaining $52$58 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050,2055, 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

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

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,

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(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.
17. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about material items recorded in the Registrants’Registrants' Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2019 and 2018.Income.
 Three Months Ended March 31, 2019
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units(b)
$54
 $54
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units54
 54
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on NDT funds                 
Regulatory agreement units(b)
379
 379
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units280
 280
 —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(c)
(348) (348) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities419
 419
 —
 —
 —
 —

—
 —
 —
Investment income12
 7
 —
 1
 —
 —
 —
 —
 —
Interest income related to uncertain income tax positions1
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity22
 —
 5
 3
 5
 9
 6
 1
 2
Non-service net periodic benefit cost5
 —
 —
 —
 —
 —
 —
 —
 —
Other8
 4
 3
 —
 —
 3
 1
 2
 1
Other, net$467

$430

$8

$4

$5
 $12

$7

$3

$3
 Taxes other than income
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended September 30, 2019                
Utility taxes(a)
$241
 $29
 $66
 $38
 $21
 $86
 $81
 $5
 $—
Property148
 66
 7
 5
 39
 31
 21
 9
 —
Payroll57
 28
 7
 3
 4
 6
 2
 1
 1
                  
Three Months Ended September 30, 2018                
Utility taxes(a)
$253
 $32
 $67
 $39
 $23
 $92
 $87
 $5
 $—
Property145
 70
 7
 4
 37
 26
 16
 9
 —
Payroll58
 31
 6
 3
 4
 5
 1
 1
 1
                  
Nine Months Ended September 30, 2019                
Utility taxes(a)
$672
 $87
 $183
 $102
 $68
 $231
 $217
 $14
 $—
Property444
 205
 22
 12
 114
 91
 64
 25
 2
Payroll185
 92
 21
 11
 13
 20
 5
 3
 2
                  
Nine Months Ended September 30, 2018                
Utility taxes(a)
$705
 $92
 $188
 $102
 $70
 $253
 $238
 $15
 $—
Property416
 204
 22
 12
 106
 71
 45
 24
 2
Payroll191
 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.

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


Note 17 — Supplemental Financial Information

 Three Months Ended March 31, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units(b)
$46
 $46
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units56
 56
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on NDT funds                 
Regulatory agreement units(b)
(75) (75) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units(96) (96) —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(c)
24
 24
 —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities(45) (45) —
 —
 —
 —

—
 —
 —
Investment income4
 2
 —
 —
 —
 —
 —
 —
 —
Interest income related to uncertain income tax positions2
 1
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity18
 —
 6
 2
 4
 6
 5
 1
 —
Non-service net periodic benefit cost(10) —
 —
 —
 —
 —
 —
 —
 —
Other3
 (2) 2
 —
 —
 5
 3
 1
 1
Other, net$(28)
$(44)
$8

$2

$4
 $11

$8
 $2
 $1
 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) —
 —
 —
 —
 —
 —
 —
 —

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(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
Nine Months Ended September 30, 2019                
Decommissioning-related activities:                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units$197
 $197
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units316
 316
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on NDT funds                 
Regulatory agreement units565
 565
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units236
 236
 —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(b)
(611) (611) —
 —
 —
 —
 —
 —
 —
Decommissioning-related activities703
 703
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity64
 —
 13
 9
 16
 26
 18
 3
 4
Non-service net periodic benefit cost8
 —
 —
 —
 —
 —
 —
 —
 —
                  
Nine Months Ended September 30, 2018                
Decommissioning-related activities:                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units$476
 $476
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units257
 257
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on NDT funds                 
Regulatory agreement units(335) (335) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units(143) (143) —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(b)
(110) (110) —
 —
 —
 —
 —
 —
 —
Decommissioning-related activities145
 145
 —
 —
 —
 —

—
 —
 —
AFUDC — Equity47
 —
 12
 3
 13
 19
 17
 2
 —
Non-service net periodic benefit cost(33) —
 —
 —
 —
 —
 —
 —
 —
_________
(a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
(b)Net realized and unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities in Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates in Generation’s Consolidated Balance Sheets.
(c)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
The following utility taxes are included
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(Dollars in revenues and expenses for the three months ended March 31, 2019 and 2018. Generation’s utility tax expense represents gross receipts tax related to its retail operations, and the Utility Registrants' utility tax expense represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.millions, except per share data, unless otherwise noted)

Note 17 — Supplemental Financial Information
 Three Months Ended March 31, 2019
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$223

$26

$62

$34

$27
 $74
 $69

$5

$—
 Three Months Ended March 31, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$235

$32

$61

$33

$26
 $83
 $77

$6

$—

Supplemental Cash Flow Information
The following tables provide additional information regardingabout material items recorded in the Registrants’Registrants' Consolidated Statements of Cash Flows for the three months ended March 31, 2019 and 2018.

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

Flows.
 Three Months Ended March 31, 2019
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization and accretion                 
Property, plant and equipment(a)
$917
 $392
 $219
 $74
 $85
 $127
 $58
 $35
 $25
Amortization of regulatory assets(a)
143
 —
 32
 7
 51
 53
 36
 11
 6
Amortization of intangible assets, net(a)
15
 13
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
261
 261
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
124
 123
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$1,460

$789

$251

$81

$136
 $180
 $94

$46

$31
Three Months Ended March 31, 2018Depreciation, amortization and accretion
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization and accretion                 
Nine Months Ended September 30, 2019Nine Months Ended September 30, 2019                
Property, plant and equipment(a)
$926
 $436
 $201
 $68
 $82
 $117
 $53
 $32
 $23
$2,803
 $1,184
 $661
 $225
 $263
 $405
 $178
 $109
 $89
Amortization of regulatory assets(a)
152
 —
 27
 7
 52
 66
 43
 13
 10
390
 —
 106
 22
 105
 157
 103
 29
 25
Amortization of intangible assets, net(a)
13
 12
 —
 —
 —
 —
 —
 —
 —
44
 37
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
3
 3
 —
 —
 —
 —
 —
 —
 —
14
 14
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
287
 287
 —
 —
 —
 —
 —
 —
 —
771
 771
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
120
 120
 —
 —
 —
 —
 —
 —
 —
371
 371
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$1,501

$858

$228

$75

$134
 $183
 $96

$45

$33
$4,393

$2,377

$767

$247

$368
 $562
 $281

$138

$114
                 
Nine Months Ended September 30, 2018Nine Months Ended September 30, 2018                
Property, plant and equipment(a)
$2,829
 $1,347
 $613
 $204
 $249
 $355
 $161
 $97
 $70
Amortization of regulatory assets(a)
412
 —
 83
 20
 109
 200
 125
 38
 37
Amortization of intangible assets, net(a)
43
 36
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
8
 8
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
852
 852
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
367
 365
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$4,511

$2,608

$696

$224

$358
 $555
 $286

$135

$107
_________
(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.


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


Note 17 — Supplemental Financial Information

 Other non-cash operating activities
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Nine Months Ended September 30, 2019                
Pension and non-pension postretirement benefit costs$324
 $98
 $70
 $9
 $45
 $71
 $19
 $11
 $12
Provision for uncollectible accounts89
 20
 26
 22
 5
 16
 7
 2
 6
Other decommissioning-related activity(a)
(400) (400) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
21
 21
 —
 —
 —
 —
 —
 —
 —
Amortization of rate stabilization deferral(8) —
 —
 —
 —
 (8) (9) 1
 —
Discrete impacts from EIMA and FEJA(c)
80
 —
 80
 —
 —
 —
 —
 —
 —
Long-term incentive plan33
 —
 —
 —
 —
 —
 —
 —
 —
Amortization of operating ROU asset193
 138
 2
 —
 23
 26
 6
 7
 4
Change in environmental liabilities23
 —
 —
 —
 —
 23
 23
 —
 —
                  
Nine Months Ended September 30, 2018                
Pension and non-pension postretirement benefit costs$435
 $151
 $133
 $14
 $43
 $51
 $10
 $5
 $10
Provision for uncollectible accounts133
 38
 30
 25
 6
 32
 12
 6
 14
Other decommissioning-related activity(a)
(39) (39) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
4
 4
 —
 —
 —
 —
 —
 —
 —
Amortization of rate stabilization deferral—
 —
 —
 —
 —
 —
 —
 —
 —
Discrete impacts from EIMA and FEJA(c)
27
 —
 27
 —
 —
 —
 —
 —
 —
Long-term incentive plan84
 —
 —
 —
 —
 —
 —
 —
 —
Asset retirement costs20
 —
 —
 —
 —
 20
 22
 (1) (1)
 Three Months Ended March 31, 2019
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:                 
Pension and non-pension postretirement benefit costs$106
 $31
 $24
 $2
 $15
 $23
 $6
 $4
 $4
Loss from equity method investments6
 6
 —
 —
 —
 —
 —
 —
 —
Provision for uncollectible accounts43
 —
 9
 16
 8
 10
 4
 4
 2
Stock-based compensation costs28
 —
 —
 —
 —
 —
 —
 —
 —
Other decommissioning-related activity(a)
(202) (202) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
37
 37
 —
 —
 —
 —
 —
 —
 —
Amortization of regulatory asset related to debt costs3
 —
 —
 —
 —
 1
 —
 —
 —
Amortization of rate stabilization deferral(6) —
 —
 —
 —
 (6) (7) 1
 —
Amortization of debt fair value adjustment(4) (3) —
 —
 —
 (1) —
 —
 —
Discrete impacts from EIMA and FEJA(c)
28
 —
 28
 —
 —
 —
 —
 —
 —
Amortization of debt costs9
 3
 1
 —
 —
 1
 1
 —
 —
Long-term incentive plan25
 —
 —
 —
 —
 —
 —
 —
 —
Amortization of operating ROU asset53
 34
 1
 —
 8
 9
 2
 2
 1
Other1
 4
 (7) (2) (4) (2) (3) —
 (2)
Total other non-cash operating activities$127

$(90)
$56

$16

$27
 $35
 $3

$11

$5
Non-cash investing and financing activities:                 
Change in capital expenditures not paid$(229) $(93) $(80) $8
 $2
 $(55) $(15) $(17) $(24)
Change in PPE related to ARO update301
 301
 —
 —
 —
 —
 —
 —
 —
Dividends on stock compensation1
 —
 —
 —
 —
 —
 —

—
 —

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

 Three Months Ended March 31, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:                 
Pension and non-pension postretirement benefit costs$145
 $51
 $45
 $5
 $14
 $15
 $4
 $—
 $3
Loss from equity method investments7
 7
 —
 —
 —
 —
 —
 —
 —
Provision for uncollectible accounts64
 11
 8
 17
 8
 20
 6
 8
 5
Stock-based compensation costs29
 —
 —
 —
 —
 —
 —
 —
 —
Other decommissioning-related activity(a)
(31) (31) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
(7) (7) —
 —
 —
 —
 —
 —
 —
Amortization of regulatory asset related to debt costs2
 —
 1
 —
 —
 1
 —
 —
 —
Amortization of rate stabilization deferral7
 —
 —
 —
 —
 7
 1
 6
 —
Amortization of debt fair value adjustment(3) (3) —
 —
 —
 —
 —
 —
 —
Discrete impacts from EIMA and FEJA(c)
(4) —
 (4) —
 —
 —
 —
 —
 —
Amortization of debt costs9
 3
 1
 —
 —
 1
 —
 —
 —
Provision for excess and obsolete inventory13
 12
 1
 —
 —
 —
 —
 —
 —
Other9
 2
 (6) (1) (2) 9
 (1) 5
 1
Total other non-cash operating activities$240

$45

$46

$21

$20
 $53
 $10

$19

$9
Non-cash investing and financing activities:                 
Change in capital expenditures not paid$(177) $(131) $(48) $(25) $(11) $61
 $19
 $14
 $27
Change in PPE related to ARO update32
 32
 —
 —
 —
 —
 —
 —
 —
Dividends on stock compensation1
 —
 —
 —
 —
 —
 —
 —
 —
________________
(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.



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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.
March 31, 2019Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$880
 $537
 $68
 $41
 $12
 $33
 $11
 $7
 $6
Restricted cash223
 139
 17
 6
 4
 39
 35
 1
 3
Restricted cash included in other long-term assets211
 —
 193
 —
 —
 19
 —
 —
 19
Total cash, cash equivalents and restricted cash$1,314
 $676
 $278
 $47
 $16
 $91
 $46
 $8
 $28

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

December 31, 2018Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$1,349
 $750
 $135
 $130
 $7
 $124
 $16
 $23
 $7
Restricted cash247
 153
 29
 5
 6
 43
 37
 1
 4
Restricted cash included in other long-term assets185
 —
 166
 —
 —
 19
 —
 —
 19
Total cash, cash equivalents and restricted cash$1,781
 $903
 $330
 $135
 $13
 $186
 $53
 $24
 $30
March 31, 2018Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$787
 $610
 $70
 $21
 $22
 $43
 $15
 $7
 $10
Restricted cash209
 127
 9
 5
 2
 40
 33
 —
 7
Restricted cash included in other long-term assets103
 —
 83
 —
 —
 20
 —
 —
 20
Total cash, cash equivalents and restricted cash$1,099
 $737
 $162
 $26
 $24
 $103
 $48
 $7
 $37
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
September 30, 2019                 
Cash and cash equivalents$1,683
 $1,019
 $76
 $224
 $130
 $99
 $18
 $11
 $13
Restricted cash309
 126
 124
 6
 1
 38
 34
 —
 3
Restricted cash included in other long-term assets186
 —
 171
 —
 —
 15
 —
 —
 15
Total cash, cash equivalents and restricted cash$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
Restricted cash247
 153
 29
 5
 6
 43
 37
 1
 4
Restricted cash included in other long-term assets185
 —
 166
 —
 —
 19
 —
 —
 19
Total cash, cash equivalents and restricted cash$1,781
 $903
 $330
 $135
 $13
 $186
 $53
 $24
 $30
                 
September 30, 2018                 
Cash and cash equivalents$1,918
 $1,187
 $124
 $102
 $113
 $153
 $12
 $110
 $11
Restricted cash240
 152
 12
 5
 3
 42
 35
 —
 7
Restricted cash included in other long-term assets163
 —
 144
 —
 —
 19
 —
 —
 19
Total cash, cash equivalents and restricted cash$2,321
 $1,339
 $280
 $107
 $116
 $214
 $47
 $110
 $37
                 
December 31, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE                 
Cash and cash equivalents$898
 $416
 $76
 $271
 $17
 $30
 $5
 $2
 $2
$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 assets and liabilitiesmaterial 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


118
Table of the Registrants as of March 31, 2019 and December 31, 2018.Contents
March 31, 2019Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:                 
Accumulated depreciation and amortization$23,695
(a) 
$12,663
(a)  
$4,833

$3,598

$3,670
 $930
 $3,392

$1,354

$1,154
Accounts receivable:                 
Allowance for uncollectible accounts$340

$87

$97

$72

$27
 $57
 $23

$15

$19
December 31, 2018Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:                 
Accumulated depreciation and amortization$22,902
(b) 
$12,206
(b) 
$4,684

$3,561

$3,633
 $841
 $3,354

$1,329

$1,137
Accounts receivable:                 
Allowance for uncollectible accounts$319

$104

$81

$61

$20
 $53
 $21

$13

$19
_________
(a)Includes accumulated amortization of nuclear fuel in the reactor core of $3,040 million.
(b)Includes accumulated amortization of nuclear fuel in the reactor core of $2,969 million.

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


Note 17 — Supplemental Financial Information
The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO and ACE purchase receivables at face value and recover uncollectible accounts expense, including those from alternative retail electric and natural gas supplies, through base distribution rates and a rate rider, respectively. Exelon and the Utility Registrants do not record unbilled commodity receivables under their POR programs. Purchased billed receivables are recorded on a net basis in Exelon’s and the Utility Registrant's Consolidated Statements of Operations and Comprehensive Income and are classified in Other accounts receivable, net in their Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of March 31, 2019 and December 31, 2018.
 Accrued expenses
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
September 30, 2019                 
Compensation-related accruals(a)
$880
 $336
 $133
 $48
 $63
 $86
 $26
 $17
 $13
Taxes accrued431
 247
 56
 13
 64
 80
 61
 17
 3
Interest accrued421
 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
Taxes accrued412
 226
 71
 28
 46
 74
 58
 4
 5
Interest accrued334
 77
 105
 33
 39
 50
 25
 8
 12
March 31, 2019Exelon ComEd PECO BGE PHI Pepco DPL ACE
Purchased receivables$332
 $105
 $77
 $65
 $85
 $58
 $8
 $19
Allowance for uncollectible accounts(a)
(38) (19) (6) (4) (9) (5) (1) (3)
Purchased receivables, net$294
 $86
 $71
 $61
 $76
 $53
 $7
 $16
December 31, 2018Exelon ComEd PECO BGE PHI Pepco DPL ACE
Purchased receivables$313
 $94
 $74
 $61
 $84
 $57
 $8
 $19
Allowance for uncollectible accounts(a)
(34) (17) (5) (3) (9) (5) (1) (3)
Purchased receivables, net$279
 $77

$69
 $58
 $75
 $52
 $7
 $16
___________________
(a)For ComEd, BGE, PepcoPrimarily includes accrued payroll, bonuses and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through a rate rider. BGE, Pepcoother incentives, vacation and DPL recover actual write-offs which are reflected in the POR discount rate.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.
•
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.
Other Power Regions:
New England represents the operations within ISO-NE.

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

South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM.
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.
•
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’

119
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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 nine months ended March 31,September 30, 2019 and 2018 is as follows:
Three Months Ended March 31,September 30, 2019 and 2018
 
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Operating revenues(c):
               
2019
Competitive businesses electric revenues$4,314
 $—
 $—
 $—
 $—
 $—
 $(275) $4,039
Competitive businesses natural gas revenues265
 —
 —
 —
 —
 —
 1
 266
Competitive businesses other revenues195
 —
 —
 —
 —
 —
 (1) 194
Rate-regulated electric revenues—
 1,583
 716
 619
 1,357
 —
 (7) 4,268
Rate-regulated natural gas revenues—
 —
 62
 84
 20
 —
 (3) 163
Shared service and other revenues—
 —
 —
 —
 3
 474
 (478) (1)
Total operating revenues$4,774
 $1,583
 $778
 $703
 $1,380
 $474
 $(763) $8,929


120
 
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Operating revenues(c):
               
2019
Competitive businesses electric revenues$4,337
 $—
 $—
 $—
 $—
 $—
 $(315) $4,022
Competitive businesses natural gas revenues879
 —
 —
 —
 —
 —
 (1) 878
Competitive businesses other revenues80
 —
 —
 —
 —
 —
 (1) 79
Rate-regulated electric revenues—
 1,408
 620
 658
 1,153
 —
 (8) 3,831
Rate-regulated natural gas revenues—
 —
 280
 318
 71
 —
 (4) 665
Shared service and other revenues—
 —
 —
 —
 4
 455
 (457) 2
Total operating revenues$5,296
 $1,408
 $900
 $976
 $1,228
 $455
 $(786) $9,477
Table of Contents

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
2018
Competitive businesses electric revenues$4,741
 $—
 $—
 $—
 $—
 $—
 $(306) $4,435
Competitive businesses natural gas revenues397
 —
 —
 —
 —
 —
 —
 397
Competitive businesses other revenues140
 —
 —
 —
 —
 —
 (1) 139
Rate-regulated electric revenues—
 1,598
 700
 645
 1,334
 —
 (7) 4,270
Rate-regulated natural gas revenues—
 —
 57
 86
 24
 —
 (5) 162
Shared service and other revenues—
 —
 —
 —
 3
 458
 (461) —
Total operating revenues$5,278
 $1,598
 $757
 $731
 $1,361
 $458
 $(780) $9,403
Intersegment revenues(d):
               
2019$275
 $4
 $1
 $6
 $4
 $474
 $(764) $—
2018308
 4
 2
 6
 3
 456
 (779) —
Depreciation and amortization:               
2019$407
 $259
 $83
 $116
 $193
 $25
 $—
 $1,083
2018468
 237
 75
 110
 192
 23
 —
 1,105
Operating expenses:               
2019$4,274
 $1,256
 $595
 $612
 $1,124
 $457
 $(759) $7,559
20184,961
 1,275
 603
 628
 1,116
 459
 (790) 8,252
Interest expense, net:               
2019$109
 $91
 $33
 $31
 $66
 $79
 $—
 $409
2018101
 85
 32
 27
 65
 83
 —
 393
Income (loss) before income taxes:               
2019$501
 $245
 $154
 $67
 $203
 $(68) $—
 $1,102
2018389
 245
 124
 81
 191
 (83) —
 947
Income Taxes:               
2019$87
 $45
 $14
 $12
 $14
 $—
 $—
 $172
201878
 52
 (2) 18
 4
 (13) —
 137
Net income (loss):              
2019$244
 $200
 $140
 $55
 $189
 $(68) $—
 $760
2018300
 193
 126
 63
 187
 (69) —
 800
Capital Expenditures               
2019$392
 $452
 $228
 $300
 $308
 $7
 $—
 $1,687
2018362
 514
 204
 233
 359
 18
 —
 1,690


121
 
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
2018
Competitive businesses electric revenues$4,509
 $—
 $—
 $—
 $—
 $—
 $(391) $4,118
Competitive businesses natural gas revenues955
 —
 —
 —
 —
 —
 (8) 947
Competitive businesses other revenues48
 —
 —
 —
 —
 —
 —
 48
Rate-regulated electric revenues—
 1,512
 634
 658
 1,169
 —
 (18) 3,955
Rate-regulated natural gas revenues—
 —
 232
 319
 78
 —
 (4) 625
Shared service and other revenues—
 —
 —
 —
 4
 451
 (455) —
Total operating revenues$5,512
 $1,512
 $866
 $977
 $1,251
 $451
 $(876) $9,693
Intersegment revenues(d):
               
2019$317
 $4
 $1
 $6
 $4
 $453
 $(785) $—
2018400
 14
 2
 6
 4
 450
 (876) —
Depreciation and amortization:               
2019$405
 $251
 $81
 $136
 $180
 $22
 $—
 $1,075
2018448
 228
 75
 134
 183
 23
 —
 1,091
Operating expenses:               
2019$4,963
 $1,135
 $678
 $756
 $1,054
 $459
 $(783) $8,262
20185,218
 1,223
 724
 800
 1,125
 444
 (886) 8,648
Interest expense, net:               
2019$111
 $87
 $33
 $29
 $65
 $78
 $—
 $403
2018101
 89
 33
 25
 63
 60
 —
 371
Income (loss) before income taxes:               
2019$652
 $197
 $193
 $196
 $122
 $(78) $—
 $1,282
2018202
 211
 111
 156
 74
 (52) —
 702
Income Taxes:               
2019$224
 $40
 $25
 $36
 $5
 $(20) $—
 $310
20189
 46
 (2) 28
 9
 (31) —
 59
Net income (loss):              
2019$422
 $157
 $168
 $160
 $117
 $(58) $—
 $966
2018186
 165
 113
 128
 65
 (21) —
 636
Capital Expenditures               
2019$511
 $503
 $222
 $258
 $358
 $21
 $—
 $1,873
2018628
 531
 217
 224
 258
 22
 —
 1,880
Total assets:              
March 31, 2019$48,682
 $31,582
 $10,956
 $9,967
 $22,294
 $8,325
 $(10,213) $121,593
December 31, 201847,556
 31,213
 10,642
 9,716
 21,984
 8,355
 (9,800) 119,666
Table of Contents

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 $45$43 million, sales to BGE of $76$65 million, sales to Pepco of $70$65 million, sales to DPL of $23$14 million and sales to ACE of $8$3 million in the Mid-Atlantic region, and sales to ComEd of $94$83 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $37$35 million, sales to BGE of $65$69 million, sales to Pepco of $52$46 million, sales to DPL of $46$26 million and sales to ACE of $6$10 million in the Mid-Atlantic region, and sales to ComEd of $194$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.


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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$642
 $299
 $419
 $—
 $(3) $1,357
Rate-regulated natural gas revenues—
 20
 —
 —
 —
 20
Shared service and other revenues—
 —
 —
 92
 (89) 3
Total operating revenues$642
 $319
 $419
 $92
 $(92) $1,380
2018           
Rate-regulated electric revenues$628
 $304
 $406
 $—
 $(4) $1,334
Rate-regulated natural gas revenues—
 24
 —
 —
 —
 24
Shared service and other revenues—
 —
 —
 103
 (100) 3
Total operating revenues$628
 $328
 $406
 $103
 $(104) $1,361
Intersegment revenues:           
2019$2
 $1
 $1
 $93
 $(93) $4
20182
 2
 1
 103
 (105) 3
Depreciation and amortization:           
2019$95
 $46
 $43
 $9
 $—
 $193
201899
 47
 38
 8
 —
 192
Operating expenses:           
2019$515
 $268
 $340
 $95
 $(94) $1,124
2018516
 277
 322
 105
 (104) 1,116
Interest expense, net:           
2019$33
 $15
 $15
 $3
 $—
 $66
201832
 15
 16
 2
 —
 65
Income (loss) before income taxes:           
2019$103
 $38
 $65
 $192
 $(195) $203
201887
 38
 69
 179
 (182) 191
Income Taxes:           
2019$5
 $5
 $2
 $3
 $(1) $14
2018(2) 5
 8
 (8) 1
 4
Net income (loss):           
2019$98
 $33
 $63
 $(9) $4
 $189
201889
 33
 61
 1
 3
 187
Capital Expenditures           
2019$157
 $85
 $73
 $(7) $—
 $308
2018188
 88
 77
 6
 —
 359
 Pepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHI
Operating revenues(a):
2019           
Rate-regulated electric revenues$575
 $310
 $273
 $—
 $(5) $1,153
Rate-regulated natural gas revenues—
 70
 —
 —
 1
 71
Shared service and other revenues—
 —
 —
 106
 (102) 4
Total operating revenues$575
 $380
 $273
 $106
 $(106) $1,228
2018           
Rate-regulated electric revenues$557
 $306
 $310
 $—
 $(4) $1,169
Rate-regulated natural gas revenues—
 78
 —
 —
 —
 78
Shared service and other revenues—
 —
 —
 113
 (109) 4
Total operating revenues$557
 $384
 $310
 $113
 $(113) $1,251
Intersegment revenues:           
2019$2
 $2
 $1
 $105
 $(106) $4
20182
 2
 1
 112
 (113) 4
Depreciation and amortization:           
2019$94
 $46
 $31
 $10
 $(1) $180
201896
 45
 33
 9
 —
 183
Operating expenses:           
2019$491
 $308
 $252
 $108
 $(105) $1,054
2018501
 335
 287
 114
 (112) 1,125
Interest expense, net:           
2019$34
 $15
 $14
 $3
 $(1) $65
201831
 13
 16
 2
 1
 63
Income (loss) before income taxes:           
2019$57
 $60
 $10
 $113
 $(118) $122
201833
 38
 8
 64
 (69) 74
Income Taxes:           
2019$2
 $7
 $—
 $(4) $—
 $5
20182
 7
 1
 (1) —
 9
Net income (loss):           
2019$55
 $53
 $10
 $(5) $4
 $117
201831
 31
 7
 (8) 4
 65
Capital Expenditures           
2019$144
 $78
 $128
 $8
 $—
 $358
2018127
 65
 63
 3
 —
 258
Total assets:           
March 31, 2019$8,420
 $4,660
 $3,783
 $10,909
 $(5,478) $22,294
December 31, 20188,299
 4,588
 3,699
 10,819
 (5,421) 21,984

__________
(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


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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 September 30, 2019
 
Revenues from external customers(a)
 Intersegment
revenues
Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$1,351
 $10
 $1,361
 $3
 $1,364
Midwest1,052
 47
 1,099
 (17) 1,082
New York414
 15
 429
 —
 429
ERCOT288
 72
 360
 5
 365
Other Power Regions873
 192
 1,065
 (25) 1,040
Total Competitive Businesses Electric Revenues3,978
 336
 4,314
 (34) 4,280
Competitive Businesses Natural Gas Revenues160
 105
 265
 34
 299
Competitive Businesses Other Revenues(c)
112
 83
 195
 —
 195
Total Generation Consolidated Operating Revenues$4,250
 $524
 $4,774
 $—
 $4,774

 Three Months Ended September 30, 2018
 
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$1,397
 $52
 $1,449
 $7
 $1,456
Midwest1,095
 26
 1,121
 (4) 1,117
New York475
 (6) 469
 —
 469
ERCOT156
 289
 445
 (1) 444
Other Power Regions959
 298
 1,257
 (45) 1,212
Total Competitive Businesses Electric Revenues4,082
 659
 4,741
 (43) 4,698
Competitive Businesses Natural Gas Revenues200
 197
 397
 43
 440
Competitive Businesses Other Revenues(c)
130
 10
 140
 —
 140
Total Generation Consolidated Operating Revenues$4,412
 $866
 $5,278
 $—
 $5,278
__________
(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 $77 million and $6 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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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 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
Mid-Atlantic$684
 $5
 $689
 $746
 $17
 $763
Midwest763
 (16) 747
 763
 5
 768
New York288
 3
 291
 290
 2
 292
ERCOT76
 (4) 72
 161
 (63) 98
Other Power Regions212
 (28) 184
 226
 (46) 180
Total Revenues net of purchased power and fuel for Reportable Segments2,023

(40)
1,983

2,186

(85)
2,101
Other(b)
100
 40
 140
 112
 85
 197
Total Generation Revenues net of purchased power and fuel expense$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 gains of $17 million and $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 $3 million and $18 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

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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

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

Note 18 — Segment Information

 Three Months Ended September 30, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$861
 $458
 $366
 $726
 $306
 $180
 $240
Small commercial & industrial391
 108
 68
 140
 39
 48
 53
Large commercial & industrial131
 64
 117
 303
 230
 25
 48
Public authorities & electric railroads11
 7
 7
 14
 8
 3
 3
Other(a)
212
 59
 91
 156
 47
 47
 63
Total rate-regulated electric revenues(b)
$1,606
 $696
 $649
 $1,339
 $630
 $303
 $407
Rate-regulated natural gas revenues             
Residential$—
 $36
 $46
 $8
 $—
 $8
 $—
Small commercial & industrial—
 15
 8
 5
 —
 5
 —
Large commercial & industrial—
 —
 17
 2
 —
 2
 —
Transportation—
 5
 —
 3
 —
 3
 —
Other(c)
—
 1
 12
 6
 —
 6
 —
Total rate-regulated natural gas revenues(d)
$—
 $57
 $83
 $24
 $—
 $24
 $—
Total rate-regulated revenues from contracts with customers$1,606
 $753
 $732
 $1,363
 $630
 $327
 $407
              
Other revenues             
Revenues from alternative revenue programs$(15) $1
 $(6) $(5) $(4) $—
 $(1)
Other rate-regulated electric revenues(e)
7
 3
 4
 3
 2
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 1
 —
 —
 —
 —
Total other revenues$(8) $4
 $(1) $(2) $(2) $1
 $(1)
Total rate-regulated revenues for reportable segments$1,598
 $757
 $731
 $1,361
 $628
 $328
 $406
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $4 million, $1 million, $2 million, $4 million, $2 million, $1 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $4 million, $2 million, $1 million, $3 million $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, 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.

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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

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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
Income (loss) before income taxes:               
2019$1,355
 $674
 $461
 $320
 $436
 $(218) $—
 $3,028
2018800
 663
 331
 301
 363
 (195) —
 2,263
Income Taxes:               
2019$388
 $130
 $51
 $59
 $25
 $(27) $—
 $626
2018110
 140
 (5) 59
 28
 (70) —
 262
Net income (loss):               
2019$784
 $544
 $410
 $261
 $412
 $(191) $—
 $2,220
2018667
 523
 336
 242
 336
 (125) —
 1,979
Capital Expenditures               
2019$1,282
 $1,413
 $675
 $842
 $1,006
 $41
 $—
 $5,259
20181,660
 1,540
 615
 667
 988
 27
 —
 5,497
Total assets:               
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
__________
(a)Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $123 million, sales to BGE of $199 million, sales to Pepco of $188 million, sales to DPL of $50 million and sales to ACE of $16 million in the Mid-Atlantic region, and sales to ComEd of $266 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $97 million, sales to BGE of $198 million, sales to Pepco of $143 million, sales to DPL of $103 million and sales to ACE of $21 million in the Mid-Atlantic region, and sales to ComEd of $419 million in the Midwest region, which eliminate upon consolidation.
(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.

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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


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

Note 18 — 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):
 Nine Months Ended September 30, 2019
 
Revenues from external customers(a)
 
Intersegment
Revenues
 
Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$3,798
 $9
 $3,807
 $2
 $3,809
Midwest3,083
 172
 3,255
 (31) 3,224
New York1,195
 16
 1,211
 —
 1,211
ERCOT594
 198
 792
 13
 805
Other Power Regions2,849
 451
 3,300
 (46) 3,254
Total Competitive Businesses Electric Revenues11,519
 846
 12,365
 (62) 12,303
Competitive Businesses Natural Gas Revenues1,041
 438
 1,479
 62
 1,541
Competitive Businesses Other Revenues(c)
343
 93
 436
 —
 436
Total Generation Consolidated Operating Revenues$12,903
 $1,377
 $14,280
 $—
 $14,280
 Three Months Ended March 31, 2019
 
Revenues from external parties(a)
 Intersegment
revenues
Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$1,286
 $(24) $1,262
 $(6) $1,256
Midwest1,055
 59
 1,114
 (6) 1,108
New York409
 (16) 393
 —
 393
ERCOT130
 79
 209
 3
 212
Other Power Regions1,165
 194
 1,359
 (6) 1,353
Total Competitive Businesses Electric Revenues4,045
 292
 4,337
 (15) 4,322
Competitive Businesses Natural Gas Revenues584
 295
 879
 15
 894
Competitive Businesses Other Revenues(c)
120
 (40) 80
 —
 80
Total Generation Consolidated Operating Revenues$4,749
 $547
 $5,296
 $—
 $5,296

Three Months Ended March 31, 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$1,355
 $80
 $1,435
 $5
 $1,440
$3,971
 $191
 $4,162
 $17
 $4,179
Midwest1,273
 71
 1,344
 2
 1,346
3,432
 169
 3,601
 (8) 3,593
New York439
 (29) 410
 (1) 409
1,305
 (37) 1,268
 1
 1,269
ERCOT149
 59
 208
 1
 209
470
 459
 929
 1
 930
Other Power Regions935
 177
 1,112
 (32) 1,080
2,656
 574
 3,230
 (116) 3,114
Total Competitive Businesses Electric Revenues4,151
 358
 4,509
 (25) 4,484
11,834
 1,356
 13,190
 (105) 13,085
Competitive Businesses Natural Gas Revenues522
 433
 955
 25
 980
1,016
 823
 1,839
 105
 1,944
Competitive Businesses Other Revenues(c)
134
 (86) 48
 —
 48
385
 (46) 339
 —
 339
Total Generation Consolidated Operating Revenues$4,807
 $705
 $5,512
 $—
 $5,512
$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 $52 million and $98$96 million in 2019 and 2018, respectively, and elimination of intersegment revenues.


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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 March 31, 2019 Three Months Ended March 31, 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$679
 $4
 $683
 $836
 $14
 $850
$2,007
 $16
 $2,023
 $2,303
 $45
 $2,348
Midwest769
 2
 771
 847
 13
 860
2,269
 (22) 2,247
 2,381
 19
 2,400
New York262
 3
 265
 282
 1
 283
800
 10
 810
 832
 9
 841
ERCOT98
 (24) 74
 106
 (70) 36
252
 (27) 225
 396
 (180) 216
Other Power Regions174
 (18) 156
 279
 (43) 236
542
 (64) 478
 740
 (133) 607
Total Revenues net of purchased power and fuel for Reportable Segments1,982

(33)
1,949

2,350

(85)
2,265
Total Revenues net of purchased power and fuel expense for Reportable Segments5,870

(87)
5,783

6,652

(240)
6,412
Other(b)
109
 33
 142
 (131) 85
 (46)262
 87
 349
 164
 240
 404
Total Generation Revenues net of purchased power and fuel expense$2,091

$—

$2,091

$2,219

$—

$2,219
$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 $28$84 million and $266$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 $5$13 million and $15$53 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.


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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 March 31, 2019Nine Months Ended September 30, 2019
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACEComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues                          
Residential$710
 $409
 $385
 $579
 $256
 $185
 $138
$2,221
 $1,231
 $1,019
 $1,816
 $792
 $499
 $525
Small commercial & industrial360
 96
 70
 120
 38
 48
 34
1,103
 304
 193
 387
 114
 141
 132
Large commercial & industrial132
 48
 110
 267
 204
 24
 39
399
 163
 335
 843
 633
 75
 135
Public authorities & electric railroads13
 7
 7
 14
 8
 3
 3
35
 23
 20
 47
 27
 10
 10
Other(a)
217
 62
 80
 157
 53
 47
 57
660
 186
 242
 481
 166
 151
 164
Total rate-regulated electric revenues(b)
$1,432
 $622
 $652
 $1,137
 $559
 $307
 $271
4,418
 1,907
 1,809
 3,574
 1,732
 876
 966
Rate-regulated natural gas revenues                          
Residential$—
 $198
 $219
 $44
 $—
 $44
 $—
—
 285
 327
 64
 —
 64
 —
Small commercial & industrial—
 72
 35
 19
 —
 19
 —
—
 122
 55
 30
 —
 30
 —
Large commercial & industrial—
 1
 50
 1
 —
 1
 —
—
 1
 93
 4
 —
 4
 —
Transportation—
 7
 —
 4
 —
 4
 —
—
 18
 —
 11
 —
 11
 —
Other(c)
—
 2
 4
 3
 —
 3
 —
—
 5
 19
 6
 —
 6
 —
Total rate-regulated natural gas revenues(d)
$—
 $280
 $308
 $71
 $—
 $71
 $—
—
 431
 494
 115
 —
 115
 —
Total rate-regulated revenues from contracts with customers$1,432
 $902
 $960
 $1,208
 $559
 $378
 $271
4,418
 2,338
 2,303
 3,689
 1,732
 991
 966
                          
Other revenues                          
Revenues from alternative revenue programs$(28) $(3) $10
 $15
 $14
 $—
 $1
(98) (16) 11
 4
 10
 (6) —
Other rate-regulated electric revenues(e)
4
 1
 3
 4
 2
 1
 1
22
 10
 10
 7
 6
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 3
 1
 —
 1
 —
—
 1
 3
 —
 —
 1
 —
Total other revenues$(24) $(2) $16
 $20
 $16
 $2
 $2
(76) (5) 24
 11
 16
 (4) —
Total rate-regulated revenues for reportable segments$1,408
 $900
 $976
 $1,228
 $575
 $380
 $273
$4,342
 $2,333
 $2,327
 $3,700
 $1,748
 $987
 $966


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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, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$2,277
 $1,199
 $1,054
 $1,839
 $792
 $513
 $534
Small commercial & industrial1,132
 306
 196
 370
 104
 138
 128
Large commercial & industrial411
 174
 325
 845
 632
 74
 139
Public authorities & electric railroads36
 21
 21
 44
 24
 10
 10
Other(a)
656
 181
 246
 446
 145
 129
 174
Total rate-regulated electric revenues(b)
4,512
 1,881
 1,842
 3,544
 1,697
 864
 985
Rate-regulated natural gas revenues             
Residential—
 259
 345
 68
 —
 68
 —
Small commercial & industrial—
 102
 55
 31
 —
 31
 —
Large commercial & industrial—
 1
 88
 7
 —
 7
 —
Transportation—
 16
 —
 12
 —
 12
 —
Other(c)
—
 4
 49
 11
 —
 11
 —
Total rate-regulated natural gas revenues(d)
—
 382
 537
 129
 —
 129
 —
Total rate-regulated revenues from contracts with customers4,512
 2,263
 2,379
 3,673
 1,697
 993
 985
              
Other revenues             
Revenues from alternative revenue programs(27) 2
 (23) 7
 6
 5
 (4)
Other rate-regulated electric revenues(e)
23
 10
 10
 8
 5
 3
 —
Other rate-regulated natural gas revenues(e)
—
 —
 3
 —
 —
 —
 —
Total other revenues(4) 12
 (10) 15
 11
 8
 (4)
Total rate-regulated revenues for reportable segments$4,508
 $2,275
 $2,369
 $3,688
 $1,708
 $1,001
 $981
 Three Months Ended March 31, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$717
 $403
 $393
 $610
 $259
 $191
 $160
Small commercial & industrial385
 101
 68
 115
 32
 46
 37
Large commercial & industrial152
 58
 106
 259
 190
 23
 46
Public authorities & electric railroads14
 8
 7
 14
 7
 4
 3
Other(a)
230
 62
 78
 156
 49
 41
 66
Total rate-regulated electric revenues(b)
$1,498
 $632
 $652
 $1,154
 $537
 $305
 $312
Rate-regulated natural gas revenues             
Residential$—
 $161
 $224
 $47
 $—
 $47
 $—
Small commercial & industrial—
 62
 34
 18
 —
 18
 —
Large commercial & industrial—
 1
 47
 4
 —
 4
 —
Transportation—
 6
 —
 5
 —
 5
 —
Other(c)
—
 2
 27
 4
 —
 4
 —
Total rate-regulated natural gas revenues(d)
$—
 $232
 $332
 $78
 $—
 $78
 $—
Total rate-regulated revenues from contracts with customers$1,498
 $864
 $984
 $1,232
 $537
 $383
 $312
              
Other revenues             
Revenues from alternative revenue programs$5
 $(1) $(13) $18
 $19
 $1
 $(2)
Other rate-regulated electric revenues(e)
9
 3
 4
 1
 1
 —
 —
Other rate-regulated natural gas revenues(e)
—
 —
 2
 —
 —
 —
 —
Total other revenues$14
 $2
 $(7) $19
 $20
 $1
 $(2)
Total rate-regulated revenues for reportable segments$1,512
 $866
 $977
 $1,251
 $557
 $384
 $310

__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $13 million, $4 million, $1$5 million, $2$11 million, $3$5 million, $2 million, $2$5 million and $1$2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $14$23 million, $2$5 million, $2$5 million, $4$11 million $2$5 million, $2$6 million and 1$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 $4$13 million at PECO and BGE respectively, in 2019 and 2018.2018, 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 is changingchanged the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation will disclosedisclosed 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.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. Additionally, the results of Exelon’s corporate operations include interest costs and income from various investment and financing activities.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.

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 nine months ended March 31,September 30, 2019 compared to the same period in 2018. For additional information regarding the financial results for the three and nine months ended March 31,September 30, 2019 and 2018 see the discussions of Results of Operations by Registrant.
Three Months Ended March 31, Favorable (unfavorable) varianceThree Months Ended September 30, Favorable (unfavorable) variance Nine Months Ended September 30, Favorable (unfavorable) variance
2019 2018 2019 2018 2019 2018 
Exelon$907
 $585
 $322
772
 733
 $39
 $2,164
 $1,858
 $306
Generation363
 136
 227
257
 234
 23
 728
 547
 181
ComEd157
 165
 (8)200
 193
 7
 544
 523
 21
PECO168
 113
 55
140
 126
 14
 410
 336
 74
BGE160
 128
 32
55
 63
 (8) 261
 242
 19
PHI117
 65
 52
189
 187
 2
 412
 336
 76
Pepco55
 31
 24
98
 89
 9
 217
 174
 43
DPL53
 31
 22
33
 33
 —
 116
 90
 26
ACE10
 7
 3
63
 61
 2
 87
 76
 11
Other(a)
(58) (22) (36)(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 March 31,September 30, 2019 Compared to Three Months Ended March 31,September 30, 2018.Net income attributable to common shareholders increased by $322$39 million and diluted earnings per average common share increased to $0.93$0.79 in 2019 from $0.60$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
Unfavorable weather conditions and volume at PECO.
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 in 2019 compared to losses in 2018;funds;
Decreased mark-to-market losses;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 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;
A benefit associated with the remeasurement of the TMI ARO;
Increased capacity prices;ARO in the first quarter of 2019 and the annual nuclear ARO update in the third quarter of 2019;
Regulatory rate increases at PECO, BGE, Pepco, DPL, and DPL;ACE; and
LowerDecreased storms costs at PECO and BGE.
The increases were partially offset by:
Lower realized energy prices andprices;
Lower capacity prices;
The absence of the revenuerevenues recognized in the first quarter of 2018 related to ZECs generated in Illinois from June through December 2017.2017, partially offset by increased New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 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 nine months ended March 31,September 30, 2019 compared to the same period in 2018.
 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

 Three Months Ended March 31,
 2019 2018
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$907
 $0.93
 $585
 $0.60
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $12 and $69, respectively)31
 0.03
 197
 0.20
Unrealized Losses (Gains) Related to NDT Fund Investments(a) (net of taxes of $161 and $45, respectively)
(193) (0.20) 66
 0.07
PHI Merger and Integration Costs (net of taxes of $1)
—
 —
 3
 —
Long-Lived Asset Impairments (net of taxes of $1)
4
 —
 —
 —
Plant Retirements and Divestitures(b) (net of taxes of $6 and $32, respectively)
19
 0.02
 92
 0.10
Cost Management Program(c) (net of taxes of $3 and $1, respectively)
11
 0.01
 5
 0.01
Noncontrolling Interests(d) (net of taxes of $13 and $5, respectively)
67
 0.07
 (23) (0.02)
Adjusted (non-GAAP) Operating Earnings$846
 $0.87
 $925
 $0.96
 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 20182019 and 20172018 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.Thefunds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 45.447.1 percent and 40.37.7 percent for the three months ended March 31,September 30, 2019 and 2018, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 48.1 percent and 55.5 percent for the nine months ended September 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 and accelerated depreciation and amortization expensesfacilities, a charge associated with a remeasurement of the 2017 decision to early retire the TMI 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 Generation's previous decision tothe early retireretirement of the TMI nuclear facility and certain fossil sites and the loss on the sale of Oyster Creek to Holtec, partially offset by net realized gains related to Oyster Creek's NDT fund investments, a net benefit associated with a remeasurementremeasurements of the TMI ARO.ARO and a gain on the sale of certain wind assets.
(c)(d)Primarily represents reorganization costs related to cost management programs.
(d)(e)
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.
(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 IncreaseApproved Revenue Requirement Increase (Decrease)Approved 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, 2019
PECO - Pennsylvania (Electric)March 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 IncreaseRequested ROEExpected Approval TimingFiling DateRequested Revenue Requirement (Decrease) IncreaseRequested ROEExpected Approval Timing
Pepco - Maryland (Electric)January 15, 2019 (amended April 30, 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)(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 (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) 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 ROE
ComEd21
(16)5
8.21%11.50%
BGE(10)(23)(19)7.35%10.50%
Pepco15
11
26
7.75%10.50%
DPL17
(1)16
7.14%10.50%
ACE11
(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. ThePECO’s initial formula rate filing includesincluded a requested increase of  $22 million to PECO’s annual transmission revenues andrevenue requirement, which reflected a requested rate of return on common equityROE of  11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017.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 May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. On February 8,July 22, 2019, PECO and the active parties reached an agreement in principle to settle this case. The presiding Administrative Law Judge has since suspended the procedural schedule in order for PECO and the active parties to continue working towards finalizing a settlement. On April 15, 2019, PECO and the activeother parties filed with FERC a status update withsettlement agreement, which includes a ROE of 10.35%, inclusive of a 50 basis point adder for being a member of a RTO. The settlement did not have a material impact on PECO’s 2017, 2018, or 2019 annual transmission revenue requirements. A final order from FERC is expected before the presiding Administrative Law Judge requesting an additional 45 days to file a settlement.end of the first quarter of 2020. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a revenue decrease of $6 million. The revenue decrease of $6 million included an approximately $20 million reduction as a result of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.

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 March 31, 2019, Generation had approximately $750 million and $500 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 as of March 31, 2019.
Generation assessed and determined that Antelope Valley’s long-lived assets were not impaired as of March 31, 2019. 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 Assets and Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the PG&E bankruptcy.
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 currently anticipates satisfaction ofrecognized a loss on the closing conditions for the transaction to occursale in the second half of 2019.third quarter 2019, 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, 2019. The plant is currently committed to operate through May20, 2019. As a result of the previous decision to early retire TMI, Exelon and Generation recorded a $4$113 million and $185 million incremental pre-tax net benefitcharge for the three and nine months ended March 31,September 30, 2019 primarily due to accelerated depreciation of the plant assets, partially offset by a benefit associated with the remeasurement of the TMI ARO partially offset by accelerated depreciationin the first quarter of the plant assets. 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.2019.
Salem. In 2017, PSEG announced that its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest, were showing increased signs of economic distress, which could lead to an early retirement. PSEG is the operator of Salem and also has the decision 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, operates as expected, 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 September 30, 2019, Generation had approximately $730 million and $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 Strategy and Outlook forGeneration’s Consolidated Balance Sheets in the first quarter of 2019 and Beyondcontinues to be classified as current as of September 30, 2019.
Exelon’s value propositionIn the first quarter of 2019, Generation assessed and competitive advantage come from its scope and its core strengths of operational excellence and financial discipline. Exelon leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mix of attributesdetermined that when combined, offer shareholders and customers a unique value proposition:
The Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currencyAntelope Valley’s long-lived assets were not impaired. Significant changes in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily inassumptions such as the utilities and in long-term, contracted assets and to reduce debt.
Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid and smart meter technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Exelon’s financial priorities are to maintain investment grade credit metrics at eachlikelihood of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon's Board of Directors has approved a dividend policy providing a raise of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORSPPA being rejected as part of the Exelon 2018 Form 10-Kbankruptcy 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 additional information regarding market and financial factors.
Continually optimizingany changes in circumstances that would indicate the cost structure is a key component of Exelon’s financial strategy.  In August 2015, Exelon announced a cost management program focused on cost savings of approximately $400 million at BSC and Generation, which was fully realized in 2018.  Approximately 75%carrying amount of the savings were related to Generation, with the remaining amount related to the Utility Registrants. In November 2017, Exelon announced a commitment for an additional $250 millionnet long-lived assets of cost savings, primarily at Generation, toAntelope Valley may not be achieved by 2020. In November 2018, Exelon announced the elimination of an approximately additional $200 million of annual ongoing costs, through initiatives primarily at Generation and BSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity.

Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The Utility Registrants anticipate investing approximately $29 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $13 billion by the end of 2023. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.recoverable.
See Note 47 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements Exelon 2018 Form 10-K for additional information on the Smart Meter and Smart Grid Initiatives and infrastructure development and enhancement programs.
Competitive Energy Businesses. Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.
Liquidity Considerations
Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
Exelon Corporate, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities. Generation also has bilateral credit facilities. Refer to Note 13 — Debt and Credit Agreements of the Exelon 2018 Form 10-K for additional information on credit facilities.
For additional information regarding the Registrants' liquidity for the three months ended March 31, 2019, see Liquidity and Capital Resources discussion below.
Project Financing
Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities. See Note 13 — Debt and Credit Agreements of the Exelon 2018 Form 10-K for additional information on nonrecourse debtAsset Impairments and Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Pacific Gas and Electric CompanyPG&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
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs
PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR)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 that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS programs that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, (Quad Cities, Ginna, Fitzpatrick, Nine Mile Point and Salem, of which Generation owns a 42.59% interest), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions, such that these facilities would haveresulting in an increased risk of these facilities not clearing in future capacity auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any mitigation of these generating resourcesin 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 based on that complaint and a related PJM filing that PJM’s existing tariff allows resources receiving out-of-market support to affect capacity prices in a manner that will cause unjust and unreasonable and unduly discriminatory rates in PJM regardless of the intent motivating the support.PJM. FERC suggested that modifying two elements of PJM’s existing tariff, as follows could produce a just and reasonable replacement and asked for initial comments on its proposal by August 28, 2018, later extended to October 2, 2018. First, FERC found that anreplacement.
An expansion of the current MOPR mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or REC compensation, could protect the capacity markets from unwanted price suppression. Second, FERC preliminarily found that a
A modified version of PJM’s existing Fixed Resource Requirement (FRR) option could enable state subsidized resources and a corresponding amount of load to be removed from the capacity market, thereby alleviating their price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through mechanisms other than through PJM’s existing market mechanism.
FERC established March 21, 2016 as the refund effective date and also allowed PJM to delay its next capacity auction from May 2019 to August 2019 to allow parties time to develop and file proposals in the FERC proceeding, FERC time to determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates, environmental organizations and other nuclear generators, submitted shared principles supporting a workable new FRR mechanism (as suggested by FERC) and detailing how such a mechanism should be implemented. Exelon also submitted individual comments covering matters not addressed in the shared principles.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, 2019.2019 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 now hasfound 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 daysdays. On October 10, 2019, the President granted a 30-day extension to decide whether and howthe deadline for the Working Group to act onsubmit the Secretary's recommendations.report. The relief soughtWorking Group is to be co-chaired by the petitioners would require U.S. nuclear reactorsAssistant to purchase at least 25% of their uranium needs from domestic mines for the next 10 years or more, although the President could choose this remedy or any other remedy, whether recommended byfor National Security Affairs and the DOC or not, or could chooseAssistant to take no action.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 this investigation. It is reasonably possible that if this petition is successful the resulting increase in nuclear fuel costs in future periods could have a material, unfavorable impact on Exelon’sWorking Group report and Generation’s financial statements.subsequent actions.
Energy Demand
Modest economic growth partially offset by energy efficiency initiatives is resulting in relatively flat load growth in electricity for the Utility Registrants. ComEd, PECO, BGE, DPL and ACE are projecting load volumes to increase (decrease) by (0.2)%, (0.3)%, 1.3%, (0.7)% and (1.9)% respectively, in 2019 compared to 2018. Pepco is projecting load volumes to be flat in 2019 compared to 2018.
Retail Competition
Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. Forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.
Strategic Policy Alignment
As part of its strategic business planning process, Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices and the impacts of hypothetical credit downgrades.
Exelon's board of directors declared first quarter 2019 dividends of $0.3625 per share on Exelon's common stock. The first quarter 2019 dividend was paid on March 8, 2019.
Exelon's board of directors declared second quarter 2019 dividends of $0.3625 per share on Exelon's common stock and is payable on June 10, 2019.

Exelon's Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
All future quarterly dividends require approval by Exelon's Board of Directors.
Hedging Strategy
Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2019 and 2020. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of March 31,September 30, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 90%-93%96%-99%, 64%-67%84%-87% and 38%-41%54%-57% for 2019, 2020, and 2021 respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.risk.
Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel isassemblies 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 coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 62%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
Exelon was actively involved in the Obama Administration’s development and implementation of environmental regulations for the electric industry, in pursuit of its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil fuel plants.
Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.
In particular, the Administration has targeted certain existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration

on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings and withdrew all technical support documents supporting the calculation. Other regulations that are under review include the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015 National Ambient Air Quality Standard (NAAQS) for ozone. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.
Air Quality
Mercury and Air Toxics Standard Rule (MATS). On December 16, 2011, the EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. The initial compliance deadline to meet the new standards was April 16, 2015; however, facilities may have been granted an additional one or two-year extension in limited cases. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court to take further action consistent with the U.S. Supreme Court’s opinion on this single issue. On April 27, 2017, the D.C. Circuit granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. Notwithstanding the Court’s order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule. On December 28, 2018, the EPA proposed to revoke the "appropriate and necessary" finding underpinning the MATS rule. While the proposal would leave the rule in place, it would leave it vulnerable to future legal challenge.
Clean Power Plan.On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. On October 10, 2017,In June 2019, EPA issued a proposedfinal rule to repealthat repealed the CPP, in its entirety, based on a proposed change inand finalized the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. Subsequently, on August 31, 2018, EPA proposed its Affordable Clean Energy Rule, which wouldrule to replace the CPP with revised emissionless stringent emissions guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants.
2015 Ozone National Ambient Air Quality Standards (NAAQS). On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. Concurrent with its review, the Agency issued several rounds of final ozone designations for the 2015 ozone NAAQS in December 2017 and April 2018. On August 1, 2018, EPA filed a status report to the Court that indicated Agency does not intend to revise or repeal the 2015 ozone standard at this time. Subsequently the Court ordered the case reactivated.
Primary SO2 National Ambient Air Quality Standards (NAAQS). EPA took final action on April 17, 2019 to retain the current primary SO2 standard without revision, leaving the standard established in 2010 in effect.
Climate Change. Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In the absence of Federal legislation, the EPA is moving forward with the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the international regulation of GHG emissions pursuant to the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). See ITEM 1. BUSINESS, "Air Quality" of the Exelon 2018 Form 10-K for additional information.

Water Quality
Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by recent changes to the regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mystic Unit 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities, and Salem. See ITEM 1. BUSINESS, "Water Quality" of the Exelon 2018 Form 10-K for additional information.
Solid and Hazardous Waste
In October 2015, the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants became effective. The rule classified CCR as non-hazardous waste under RCRA, and CCR continued to be regulated by most states subject to coordination with the federal regulations. In July 2018, the EPA issued a final rule amending the 2015 rule that provides more compliance flexibility to the states and owners and operators of coal ash disposal sites. Generation currently does not own or operate any such sites subject to the CCR rule. Generation previously recorded accruals consistent with state regulation for its owned coal ash sites, and as such, the CCR rule is not expected to impact Exelon’s and Generation’s financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted under the CCR rule for coal ash disposal sites formerly owned by Generation. For these reasons, Generation is unable to predict whether and to what extent it may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations.
See Note 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
During 2018, Generation finalized its CBA with the Security Officer’s union at Braidwood which will expire in 2021. Exelon Utilities finalized its two ACE Local 210 contracts and both will expire in 2023. Additionally, the CBA between Exelon Nuclear Security at Clinton and the SEIU Local 1 was extended so that the matter between two rival union organizations can be resolved. An election was held, and the new union named "LEOSU" prevailed. Negotiations will begin for an initial agreement with LEOSU which could result in some modifications to wages, hours and other terms and conditions of employment. Management cannot predict the outcome of such negotiations. There was an organizing effort over approximately 18 ACE control room System Operators. While an election was held with an outcome favorable to Local 210, collective bargaining over this small segment of employees will not commence until the issue of whether the System Operators are NLRA statutory supervisors is determined, and that matter is currently before the NLRB. Negotiations continue between BGE and IBEW Local 410 for a first contract and it is not certain when negotiations will conclude but we anticipate a favorable outcome. In April 2019, the CBAs with IBEW Local 15 covering employees at BSC, ComEd and Generation, waswere extended through 2024. TheIn June 2019, BGE’s union contract for approximately 1,400 employees within Local 410 was ratified, which did 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 isand 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 May 26, 2019. Negotiations have begun this month and we anticipate a positive outcome.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. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — CRITICAL ACCOUNTING POLICIES AND ESTIMATES in Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's combined 2018 Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, goodwill, purchase accounting, unamortized energy contract assets and liabilities, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies, revenue recognition and allowance for uncollectible accounts. At March 31,September 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 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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Table of Contents
Generation


Results of Operations — Generation
Three Months Ended
March 31,		 
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 
Operating revenues$5,296
 $5,512
 $(216)$4,774
 $5,278
 $(504) $14,280
 $15,368
 $(1,088)
Purchased power and fuel expense3,205
 3,293
 88
2,651
 2,980
 329
 8,148
 8,552
 404
Revenues net of purchased power and fuel expense(a)
2,091
 2,219
 (128)2,123
 2,298
 (175) 6,132
 6,816
 (684)
Other operating expenses                
Operating and maintenance1,218
 1,339
 121
1,087
 1,370
 283
 3,570
 4,126
 556
Depreciation and amortization405
 448
 43
407
 468
 61
 1,221
 1,383
 162
Taxes other than income135
 138
 3
129
 143
 14
 394
 414
 20
Total other operating expenses1,758
 1,925
 167
1,623
 1,981
 358
 5,185
 5,923
 738
Gain on sales of assets and businesses—
 53
 (53)
(Loss) gain on sales of assets and businesses(18) (6) (12) 15
 48
 (33)
Operating income333

347
 (14)482

311
 171
 962

941
 21
Other income and (deductions)                
Interest expense, net(111) (101) (10)(109) (101) (8) (336) (305) (31)
Other, net430
 (44) 474
128
 179
 (51) 729
 164
 565
Total other income and (deductions)319
 (145) 464
19
 78
 (59) 393
 (141) 534
Income before income taxes652
 202
 450
501
 389
 112
 1,355
 800
 555
Income taxes224
 9
 (215)87
 78
 (9) 388
 110
 (278)
Equity in losses of unconsolidated affiliates(6) (7) 1
(170) (11) (159) (183) (23) (160)
Net income422

186

236
244

300

(56)
784

667

117
Net income attributable to noncontrolling interests59
 50
 (9)
Net (loss) income attributable to noncontrolling interests(13) 66
 79
 56
 120
 64
Net income attributable to membership interest$363
 $136
 $227
$257
 $234
 $23
 $728
 $547
 $181
Three Months Ended March 31,September 30, 2019 Compared to Three Months Ended March 31,September 30, 2018.Net income attributable to membership interest increased by $227$23 million 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; and
Decreased Operating and maintenance expense, which includes the impacts of previous cost management programs and lower pension and OPEB costs.
The increases were partially offset by:
Lower capacity prices;

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Lower mark-to-market gains; and
Lower realized energy prices.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Net income attributable to membership interest increased by $181 million primarily due to:
Higher net unrealized and realized gains on NDT funds in 2019 compared to losses in 2018;funds;
Decreased mark-to-market losses;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 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;ARO in the first quarter of 2019 and
Increased capacity prices. the annual nuclear ARO update in the third quarter of 2019.
The increases were partially offset by:
Lower realized energy prices andprices;
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 2017.2017, partially offset by increased New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 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

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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 nine months ended March 31,September 30, 2019 and 2018, RNF by region were as follows:
Three Months Ended
March 31,		 Variance % ChangeThree Months Ended
September 30,		 Variance % Change Nine Months Ended
September 30,		 Variance % Change
2019 2018 2019 2018 2019 2018 
Mid-Atlantic(a)
$683
 $850
 $(167) (19.6)%$689
 $763
 $(74) (9.7)% $2,023
 $2,348
 $(325) (13.8)%
Midwest(b)
771
 860
 (89) (10.3)%747
 768
 (21) (2.7)% 2,247
 2,400
 (153) (6.4)%
New York265
 283
 (18) (6.4)%291
 292
 (1) (0.3)% 810
 841
 (31) (3.7)%
ERCOT74
 36
 38
 105.6 %72
 98
 (26) (26.5)% 225
 216
 9
 4.2 %
Other Power Regions156
 236
 (80) (33.9)%184
 180
 4
 2.2 % 478
 607
 (129) (21.3)%
Total electric revenue net of purchased power and fuel expense1,949
 2,265
 (316) (14.0)%1,983
 2,101
 (118) (5.6)% 5,783
 6,412
 (629) (9.8)%
Proprietary Trading4
 6
 (2) (33.3)%(1) 5
 (6) (120.0)% 10
 39
 (29) (74.4)%
Mark-to-market losses(28) (266) 238
 (89.5)%
Mark-to-market gains (losses)17
 71
 (54) (76.1)% (84) (104) 20
 (19.2)%
Other166
 214
 (48) (22.4)%124
 121
 3
 2.5 % 423
 469
 (46) (9.8)%
Total revenue net of purchased power and fuel expense$2,091
 $2,219
 $(128) (5.8)%$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
March 31,		 Variance % ChangeThree Months Ended
September 30,		 Variance % Change Nine Months Ended
September 30,		 Variance % Change
Supply source (GWhs)2019 2018 2019 2018 2019 2018 
Nuclear Generation(a)                      
Mid-Atlantic(a)
15,080
 16,229
 (1,149) (7.1)%
Mid-Atlantic15,281
 16,197
 (916) (5.7)% 44,436
 48,924
 (4,488) (9.2)%
Midwest23,733
 23,597
 136
 0.6 %23,730
 23,834
 (104) (0.4)% 71,459
 70,532
 927
 1.3 %
New York(a)
6,902
 7,115
 (213) (3.0)%
New York7,204
 6,518
 686
 10.5 % 20,783
 19,758
 1,025
 5.2 %
Total Nuclear Generation45,715

46,941
 (1,226) (2.6)%46,215
 46,549
 (334) (0.7)% 136,678

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

 

            

 

Mid-Atlantic951
 900
 51
 5.7 %485
 853
 (368) (43.1)% 2,351
 2,660
 (309) (11.6)%
Midwest392
 455
 (63) (13.8)%262
 244
 18
 7.4 % 981
 1,020
 (39) (3.8)%
New York1
 1
 —
 — %3
 1
 2
 200.0 % 4
 3
 1
 33.3 %
ERCOT3,078
 2,949
 129
 4.4 %4,500
 3,137
 1,363
 43.4 % 10,644
 8,389
 2,255
 26.9 %
Other Power Regions3,141
 4,028
 (887) (22.0)%3,135
 3,628
 (493) (13.6)% 8,789
 10,692
 (1,903) (17.8)%
Total Fossil and Renewables7,563

8,333
 (770) (9.2)%8,385
 7,863
 522
 6.6 % 22,769

22,764
 5
 — %
Purchased Power    

 

            

 

Mid-Atlantic2,566
 766
 1,800
 235.0 %5,235
 3,504
 1,731
 49.4 % 10,359
 4,828
 5,531
 114.6 %
Midwest288
 336
 (48) (14.3)%124
 174
 (50) (28.7)% 662
 733
 (71) (9.7)%
ERCOT1,042
 1,373
 (331) (24.1)%1,329
 1,811
 (482) (26.6)% 3,585
 5,504
 (1,919) (34.9)%
Other Power Regions12,569
 9,570
 2,999
 31.3 %13,006
 12,705
 301
 2.4 % 36,693
 32,731
 3,962
 12.1 %
Total Purchased Power16,465

12,045
 4,420
 36.7 %19,694
 18,194
 1,500
 8.2 % 51,299

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

 

            

 

Mid-Atlantic(b)
18,597
 17,895
 702
 3.9 %21,001
 20,554
 447
 2.2 % 57,146
 56,412
 734
 1.3 %
Midwest(b)
24,413
 24,388
 25
 0.1 %24,116
 24,252
 (136) (0.6)% 73,102
 72,285
 817
 1.1 %
New York6,903
 7,116
 (213) (3.0)%7,207
 6,519
 688
 10.6 % 20,787
 19,761
 1,026
 5.2 %
ERCOT4,120
 4,322
 (202) (4.7)%5,829
 4,948
 881
 17.8 % 14,229
 13,893
 336
 2.4 %
Other Power Regions15,710
 13,598
 2,112
 15.5 %16,141
 16,333
 (192) (1.2)% 45,482
 43,423
 2,059
 4.7 %
Total Supply/Sales by Region69,743

67,319
 2,424
 3.6 %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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For the three and nine months ended March 31,September 30, 2019 and 2018, changes in RNF by region were as follows:
2019 vs. 2018
Increase/ (Decrease)DescriptionIncrease/ (Decrease)Three Months Ended
September 30, 2019		Increase/ (Decrease)Nine Months Ended
September 30, 2019
Mid-Atlantic$(167)
• lower realized energy prices
• decreased revenue due to permanent cease of generation operations at Oyster Creek in Q3 2018, 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

$(325)
• lower realized energy prices
• decreased revenue due to permanent cease of generation operations at Oyster Creek in Q3 2018
• increased nuclear outage days primarily at Salem
• decreased capacity prices, partially offset by
• increased ZEC revenues due to the approval of the NJ ZEC program in Q2 2019
Midwest$(89)
• 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
• increased capacity prices and
• higher realized energy prices
(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$(18)• lower realized energy 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$38
• higher realized energy prices(26)• decrease due to higher procurement costs for owned and contracted assets9
• higher realized energy prices, partially offset by
• higher procurements costs for owned and contracted assets
Other Power Regions$(80)
• 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$(2)• congestion activity(6)• congestion activity(29)• congestion activity
Mark-to-market(a)
$238
• losses on economic hedging activities of $28 million in 2019 compared to losses of $266 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 $104 million in 2018
Other$(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$(128) $(175) $(684) 
_________
(a)See Note 10 — Derivative Financial Instruments for additional information on mark-to-market losses.

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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
March 31,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2019 20182019 2018 2019 2018
Nuclear fleet capacity factor97.1% 96.5%95.5% 93.6% 95.9% 94.4%
Refueling outage days74
 68
15
 36
 145
 198
Non-refueling outage days—
 6
15
 12
 43
 20

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The changes in Operating and maintenance expenseconsisted of the following:
Three Months Ended
March 31, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting, materials(a)
$(34)$(77) $(135)
Nuclear refueling outage costs, including the co-owned Salem plants6
(35) (52)
Corporate allocations(10)(12) (41)
Insurance(b)
30
—
 31
Merger and integration costs(4)—
 (5)
Plant retirements and divestitures(c)
(101)(78) (164)
Cost management program7
Long-lived asset impairments5
Change in environmental liabilities13
 6
ARO update(d)
(66) (66)
Asset Impairments(e)
(6) (38)
Pension and non-pension postretirement benefits expense(16)(11) (44)
Allowance for uncollectible accounts(11)(1) (18)
Accretion expense(11) (28)
Other7
1
 (2)
Decrease in Operating and maintenance expense$(121)$(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 and the increase to materials and supplies inventory reserves in 2018absence of a charge associated with Generation’s decision to early retirethe remeasurement of the Oyster Creek ARO in the third quarter of 2018.
(d)Primarily reflects a benefit related to Generation's annual nuclear facility.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 Expensefor the three and nine months ended March 31,September 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 March 31,September 30, 2019 compared to the same period in 2018 decreased primarily due to Generation's sale of Oyster Creek. Gain (loss) on sales of

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assets and businesses for the nine months ended September 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.
Other, net for the three months ended March 31,September 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 primarily due to the change in the unrealized gains and losses related toactivity associated with NDT funds of Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $(85) millionbelow:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
Net unrealized gains (losses) on NDT funds(a)
$55

$72
 $236
 $(143)
Net realized gains on sale of NDT funds(a)
9
 29
 231
 164
Interest and dividend income on NDT funds(a)
24
 29
 85
 93
Contractual elimination of income tax expense(b)
31
 29
 150
 24
Other9
 20
 27
 26
Total other, net$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 17.4% and $(7) million20.1% for the three months ended March 31,September 30, 2019 and 2018, respectively, related to the contractual elimination ofrespectively. Generation's effective income tax expense associated with the NDT funds of the Regulatory Agreement Units. See Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information regarding NDT funds.
The following table provides unrealizedrates were 28.6% and realized gains (losses) on the NDT funds of the Non-Regulatory Agreement Units:
 Three Months Ended
March 31,
 2019 2018
Net unrealized gains (losses) on NDT funds$280
 $(96)
Net realized gains on sale of NDT funds29
 28
Effective income tax rates were 34.3% and 4.5%13.8% for the threenine months ended March 31,September 30, 2019 and 2018, respectively. The change is primarily related to an increase in qualified nuclear decommissioning trust fund income and a decreasereduction in renewable tax credits.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.
Net 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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Results of Operations — ComEd
Three Months Ended
March 31,		 
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 
Operating revenues$1,408
 $1,512
 $(104)$1,583
 $1,598
 $(15) $4,342
 $4,508
 $(166)
Purchased power expense485
 605
 120
577
 619
 42
 1,469
 1,702
 233
Revenues net of purchased power expense923
 907
 16
1,006
 979
 27
 2,873
 2,806
 67
Other operating expenses                
Operating and maintenance321
 313
 (8)340
 337
 (3) 967
 974
 7
Depreciation and amortization251
 228
 (23)259
 237
 (22) 767
 696
 (71)
Taxes other than income78
 77
 (1)80
 82
 2
 228
 238
 10
Total other operating expenses650
 618
 (32)679
 656
 (23) 1,962
 1,908
 (54)
Gain on sales of assets3
 3
 —
1
 —
 1
 4
 5
 (1)
Operating income276
 292
 (16)328
 323
 5
 915
 903
 12
Other income and (deductions)                
Interest expense, net(87) (89) 2
(91) (85) (6) (268) (261) (7)
Other, net8
 8
 —
8
 7
 1
 27
 21
 6
Total other income and (deductions)(79) (81) 2
(83) (78) (5) (241) (240) (1)
Income before income taxes197
 211
 (14)245
 245
 —
 674
 663
 11
Income taxes40
 46
 6
45
 52
 7
 130
 140
 10
Net income$157
 $165
 $(8)$200
 $193
 $7
 $544
 $523
 $21
Three Months Ended March 31,September 30, 2019Compared toThree Months Ended March 31, 2018.September 30, 2018. Net incomeremained relatively consistent for the three months ended March 31,September 30, 2019 as compared to the same period in 2018.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018. Net income increased $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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The changes in RNF consisted of the following:
Three Months Ended
March 31, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Electric distribution$25
$11
 $48
Transmission9
5
 27
Energy efficiency13
9
 36
Uncollectible accounts recovery, net—
(3) (5)
Other(31)5
 (39)
Total increase$16
$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.

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ComEd

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 nine months ended March 31,September 30, 2019 as compared to the same period in 2018, primarily due to the impact of higher rate base and increased operating and maintenance and depreciation expenses.expenses, offset by lower allowed ROE due to a decrease in treasury rates. See Operating and maintenance and 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 months ended March 31,September 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 nine months ended March 31,September 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 Depreciation and amortization expense discussions below and 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 threefor the nine months ended March 31,September 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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The increasechanges in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Baseline    
Labor, other benefits, contracting and materials(a)
$(6)$—
 $(4)
Pension and non-pension postretirement benefits expense(b)
(11)(8) (28)
Storm-related costs18
7
 25
BSC costs(a)
2
Uncollectible accounts expense — recovery, net(c)
(3) (5)
BSC costs12
 6
Other(a)
5
(5) (1)
Total increase$8
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 nine months ended September 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.

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ComEd

The increasechanges in Depreciation and amortization expense consisted of the following:
Three Months Ended
March 31, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase Increase
Depreciation and amortization(a)
$18
$15
 $45
Regulatory asset amortization(b)
5
7
 26
Total increase$23
$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 20.3%18.4% and 21.8%21.2% for the three months ended March 31,September 30, 2019 and 2018, respectively. Effective income tax rate was 19.3% and 21.1% for the nine months ended September 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
March 31,		 
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 
Operating revenues$900
 $866
 $34
$778
 $757
 $21
 $2,333
 $2,275
 $58
Purchased power and fuel expense331
 333
 2
246
 263
 17
 767
 818
 51
Revenues net of purchased power and fuel expense569
 533
 36
532
 494
 38
 1,566
 1,457
 109
Other operating expenses                
Operating and maintenance225
 275
 50
219
 219
 —
 643
 686
 43
Depreciation and amortization81
 75
 (6)83
 75
 (8) 247
 224
 (23)
Taxes other than income41
 41
 —
47
 46
 (1) 126
 125
 (1)
Total other operating expenses347
 391
 44
349
 340
 (9) 1,016
 1,035
 19
Gain on sales of assets—
 —
 —
 —
 1
 (1)
Operating income222
 142
 80
183
 154
 29
 550
 423
 127
Other income and (deductions)                
Interest expense, net(33) (33) —
(33) (32) (1) (100) (96) (4)
Other, net4
 2
 2
4
 2
 2
 11
 4
 7
Total other income and (deductions)(29) (31) 2
(29) (30) 1
 (89) (92) 3
Income before income taxes193
 111
 82
154
 124
 30
 461
 331
 130
Income taxes25
 (2) (27)14
 (2) (16) 51
 (5) (56)
Net income$168
 $113
 $55
$140
 $126
 $14
 $410
 $336
 $74
Three Months Ended March 31,September 30, 2019 Compared to Three Months Ended March 31,September 30, 2018. Net income increased by $55$14 million primarily due to lower storm costs, higher electric distribution rates as a result of the 2018 electric rate case settlementthat became effective January 2019 and higher natural gas distribution rates.rates, partially offset by unfavorable weather conditions and volume.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018. Net income increased by $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 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
March 31, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Electric Gas TotalElectric Gas Total Electric Gas Total
Weather$—
 $2
 $2
$(3) $(1) $(4) $(9) $(6) $(15)
Volume1
 1
 2
(7) 1
 (6) (11) 6
 (5)
Pricing14
 10
 24
42
 —
 42
 91
 14
 105
Regulatory required programs10
 4
 14
13
 1
 14
 35
 6
 41
Transmission(11) —
 (11) (17) —
 (17)
Other(7) 1
 (6)3
 —
 3
 —
 —
 —
Total increase$18
 $18
 $36
$37
 $1
 $38
 $89
 $20
 $109

Table of Contents
PECO

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended March 31,September 30, 2019 compared to the same period in 2018, RNF increased slightlyrelated to weather decreased due to favorableunfavorable weather conditions.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and nine months ended March 31,September 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 March 31,2019 2018From 2018 2019 vs. Normal
Three Months Ended September 30,2019 2018 Normal From 2018 2019 vs. Normal
Heating Degree-Days2,432
 2,397
 2,429
 1.5% 0.1%2
 13
(84.6)% (92.6)%
Cooling Degree-Days2
 —
 1
 200.0% 100.0%1,143
 1,124
 1,001
 1.7 % 14.2 %
         
Nine Months Ended September 30,         
Heating Degree-Days2,704
 2,892
 2,890
 (6.5)% (6.4)%
Cooling Degree-Days1,570
 1,506
 1,386
 4.2 % 13.3 %
Volume. Electric volume, exclusive of the effects of weather, for the three and nine months ended March 31,September 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 September 30, 2019, compared to the same period in 2018, increased due to a shift in the volume profile across classes from the commercialcustomer and industrial classes to the residential class.  Natural gas volume for the three months ended March 31, 2019, compared to the same period in 2018, increased due to strong customer growth and moderate economic growth.

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PECO

Electric Retail Deliveries to Customers (in GWhs)Three Months Ended
March 31,		 % 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 
Residential3,641
 3,628
 0.4 % 0.4 %4,106
 4,166
 (1.4)% (0.8)% 10,568
 10,741
 (1.6)% (0.5)%
Small commercial & industrial2,066
 2,029
 1.8 % 1.8 %2,203
 2,315
 (4.8)% (2.0)% 6,093
 6,273
 (2.9)% (1.7)%
Large commercial & industrial3,571
 3,703
 (3.6)% (3.6)%4,109
 4,378
 (6.1)% (6.3)% 11,449
 11,892
 (3.7)% (3.9)%
Public authorities & electric railroads195
 197
 (1.0)% (0.9)%183
 189
 (3.2)% (3.3)% 560
 568
 (1.4)% (2.0)%
Total electric retail deliveries(a)
9,473
 9,557
 (0.9)% (0.9)%10,601
 11,048
 (4.0)% (3.3)% 28,670
 29,474
 (2.7)% (2.1)%
As of March 31,As of September 30,
Number of Electric Customers2019 20182019 2018
Residential1,485,698
 1,474,555
1,489,046
 1,476,914
Small commercial & industrial153,042
 151,947
153,400
 152,253
Large commercial & industrial3,107
 3,113
3,104
 3,124
Public authorities & electric railroads9,638
 9,541
9,775
 9,561
Total1,651,485
 1,639,156
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
March 31,		 % Change 
Weather -
 Normal
% Change(b)
2019 2018 
Residential21,218
 20,574
 3.1 % 1.2 %
Small commercial & industrial10,644
 10,417
 2.2 % 0.1 %
Large commercial & industrial19
 47
 (59.6)% (10.8)%
Transportation7,973
 7,568
 5.4 % 5.6 %
Total natural gas retail deliveries(a)
39,854
 38,606
 3.2 % 1.7 %

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PECO

Natural Gas Deliveries to Customers (in mmcf)Three Months Ended
September 30,		 % Change 
Weather -
Normal
% Change(b)
 Nine Months Ended
September 30,		 % Change 
Weather -
Normal
% Change(b)
2019 2018  2019 2018 
Residential2,109
 2,099
 0.5 % 7.9 % 26,678
 28,562
 (6.6)% 1.1%
Small commercial & industrial1,901
 1,776
 7.0 % 15.1 % 16,585
 15,792
 5.0 % 1.2%
Large commercial & industrial10
 6
 66.7 % 12.4 % 46
 58
 (20.7)% 6.0%
Transportation5,395
 5,693
 (5.2)% (3.4)% 19,087
 19,242
 (0.8)% 1.3%
Total natural gas retail deliveries(a)
9,415
 9,574
 (1.7)% 2.5 % 62,396
 63,654
 (2.0)% 1.2%
As of March 31,As of September 30,
Number of Natural Gas Customers2019 20182019 2018
Residential483,560
 478,565
484,676
 479,732
Small commercial & industrial44,274
 44,053
43,869
 43,638
Large commercial & industrial1
 4
2
 1
Transportation744
 768
735
 761
Total528,579
 523,390
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.
(a)(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three and nine months ended March 31,September 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
March 31, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Baseline    
Labor, other benefits, contracting and materials$7
$(5) $4
Storm-related costs(a)
(56)8
 (42)
Pension and non-pension postretirement benefits expense(2)(1) (4)
BSC costs3
2
 4
Other(1)(5) (6)
(49)(1) (44)
Regulatory Required Programs    
Energy efficiency(1)1
 1
Total decrease$(50)$—
 $(43)
__________
(a)Reflects decreased storm costs due to the March 2018 winter storms.

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PECO

The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended March 31, 2019Three Months Ended September 30, 2019 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase Increase
Depreciation and amortization(a)
$5
$7
 $21
Regulatory asset amortization1
1
 2
Total increase$6
$8
 $23
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective Income Tax Rates were 13.0%9.1% and (1.8)(1.6)% for the three months ended March 31,September 30, 2019 and 2018, respectively, and 11.1% and (1.5)% for the nine months ended September 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
March 31,		 
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 
Operating revenues$976
 $977
 $(1)$703
 $731
 $(28) $2,327
 $2,369
 $(42)
Purchased power and fuel expense360
 380
 20
235
 272
 37
 804
 881
 77
Revenues net of purchased power and fuel expense616
 597
 19
468
 459
 9
 1,523
 1,488
 35
Other operating expenses                
Operating and maintenance192
 221
 29
196
 182
 (14) 569
 578
 9
Depreciation and amortization136
 134
 (2)116
 110
 (6) 368
 358
 (10)
Taxes other than income68
 65
 (3)65
 64
 (1) 195
 188
 (7)
Total other operating expenses396
 420
 24
377
 356
 (21) 1,132
 1,124
 (8)
Gain on sales of assets—
 —
 —
 —
 1
 (1)
Operating income220
 177
 43
91
 103
 (12) 391
 365
 26
Other income and (deductions)                
Interest expense, net(29) (25) (4)(31) (27) (4) (89) (78) (11)
Other, net5
 4
 1
7
 5
 2
 18
 14
 4
Total other income and (deductions)(24) (21) (3)(24) (22) (2) (71) (64) (7)
Income before income taxes196
 156
 40
67
 81
 (14) 320
 301
 19
Income taxes36
 28
 (8)12
 18
 6
 59
 59
 —
Net income$160
 $128
 $32
$55
 $63
 $(8) $261
 $242
 $19
Three Months Ended March 31,September 30, 2019Compared to Three Months Ended March 31,September 30, 2018.Net income decreased by $8 million primarily due to an increase in various expenses, partially offset by higher natural gas distribution rates that became effective January 2019.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018.Net income increased by $32$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 due to the September 2018 debt issuance.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
March 31, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Electric Gas TotalElectric Gas Total Electric Gas Total
Distribution$4
 $31
 $35
$2
 $7
 $9
 $7
 $48
 $55
Regulatory required programs(2) (3) (5)(1) 1
 —
 (6) (3) (9)
Transmission(6) —
 (6)2
 —
 2
 (3) —
 (3)
Other, net(4) (1) (5)—
 (2) (2) (4) (4) (8)
Total increase (decrease)$(8) $27
 $19
$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.

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BGE


As of March 31,As of September 30,
Number of Electric Customers2019 20182019 2018
Residential1,171,027
 1,163,887
1,174,188
 1,165,012
Small commercial & industrial113,976
 113,675
114,301
 114,082
Large commercial & industrial12,278
 12,148
12,296
 12,218
Public authorities & electric railroads266
 270
264
 263
Total1,297,547
 1,289,980
1,301,049
 1,291,575
As of March 31,As of September 30,
Number of Gas Customers2019 2018
Number of Natural Gas Customers2019 2018
Residential635,241
 631,594
636,030
 631,589
Small commercial & industrial38,322
 38,443
38,129
 38,175
Large commercial & industrial5,981
 5,874
6,005
 5,920
Total679,544
 675,911
680,164
 675,684
Distribution Revenue increased for the three and nine months ended March 31,September 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 nine months ended March 31,September 30, 2019, compared to the same period in 2018. See Operating and Maintenance Expensemaintenance expense below and Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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Other revenueincludes revenue related to service application fees, mutual assistance, revenues,administrative charges, off-system sales, and late payment charges, and off-system sales.charges.
See Note 18 — Segment Information of the Combined Notes to the Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

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BGE


The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
March 31, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Baseline    
Storm-related costs(a)
$(28)$(3) $(26)
Labor, other benefits, contracting and materials12
 16
Pension and non-pension postretirement benefits expense—
 1
Uncollectible accounts expense(1) (1)
BSC costs2
1
 2
Other(2)5
 —
(28)14
 (8)
Regulatory Required Programs    
Other(1)—
 (1)
Total decrease$(29)
Total increase (decrease)$14
 $(9)
__________
(a)ReflectsFor the nine months ended September 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
March 31, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Depreciation and amortization(a)
$5
$4
 $15
Regulatory asset amortization1
2
 3
Regulatory required programs(4)—
 (8)
Total increase$2
$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 rateswere 18.4%17.9% and 17.9%22.2% for the three months ended March 31,September 30, 2019 and 2018, respectively, and 18.4% and 19.6% for the nine months ended September 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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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
March 31,		 
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 
PHI$117
 $65
 $52
$189
 $187
 $2
 $412
 $336
 $76
Pepco55
 31
 24
98
 89
 9
 217
 174
 43
DPL53
 31
 22
33
 33
 —
 116
 90
 26
ACE10
 7
 3
63
 61
 2
 87
 76
 11
Other(a)
(1) (4) 3
(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 March 31,September 30, 2019 Compared to Three Months Ended March 31, 2018.September 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 Income increased by $52$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 transmission rates and transmission base rates,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 storm costs, and the absence of a write-offwrite-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 March 31, Favorable (Unfavorable) VarianceThree Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2019 2018 2019 2018 2019 2018 
Operating revenues$575
 $557
 $18
$642
 $628
 $14
 $1,748
 $1,708
 $40
Purchased power expense187
 182
 (5)181
 177
 (4) 513
 497
 (16)
Revenues net of purchased power expense388
 375
 13
461
 451
 10
 1,235
 1,211
 24
Other operating expenses                
Operating and maintenance118
 130
 12
135
 136
 1
 364
 383
 19
Depreciation and amortization94
 96
 2
95
 99
 4
 281
 286
 5
Taxes other than income92
 93
 1
104
 104
 —
 286
 288
 2
Total other operating expenses304
 319
 15
334
 339
 5
 931
 957
 26
Operating income84
 56
 28
127
 112
 15
 304
 254
 50
Other income and (deductions)    
    
     
Interest expense, net(34) (31) (3)(33) (32) (1) (100) (96) (4)
Other, net7
 8
 (1)9
 7
 2
 22
 23
 (1)
Total other income and (deductions)(27) (23) (4)(24) (25) 1
 (78) (73) (5)
Income before income taxes57
 33
 24
103
 87
 16
 226
 181
 45
Income taxes2
 2
 —
5
 (2) (7) 9
 7
 (2)
Net income$55
 $31
 $24
$98
 $89
 $9
 $217
 $174
 $43
Three Months Ended March 31,September 30, 2019 Compared to Three Months Ended March 31,September 30, 2018.Net income increased by $24$9 million primarily due to higher electric distribution base rates in Maryland that became effective June 2018,August 2019, higher electric distribution base 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 Network Transmission Service rate that became effective June 2018, an increase intransmission 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.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018. Net income increased by $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 storm costs.uncollectible accounts 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 March 31, 2019Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Volume$4
$4
 $11
Distribution6
9
 19
Regulatory required programs(10)(8) (26)
Transmission13
2
 22
Other3
 (2)
Total increase$13
$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

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Pepco


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 nine months ended March 31,September 30, 2019 compared to the same period in 2018, primarily due to the impact of residential customer growth.
As of March 31,As of September 30,
Number of Electric Customers2019 20182019 2018
Residential809,845
 797,105
814,412
 802,607
Small commercial & industrial54,295
 53,602
54,130
 53,700
Large commercial & industrial22,030
 21,718
22,240
 21,927
Public authorities & electric railroads153
 146
158
 147
Total886,323
 872,571
890,940
 878,381
Distribution Revenues increased for the three and nine months ended March 31,September 30, 2019 compared to the same period in 2018 primarily due to higher electric distribution base rates charged to customers in Maryland that became effective in August 2019 and June 2018 and(not reflecting the impact of TCJA), higher electric distribution base rates charged to customers(not reflecting the impact of TCJA) in the District of Columbia that became effective in August 2018.2018, 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 nine months ended March 31,September 30, 2019 compared to the same period in 2018 primarily due to an increase in the Network Transmission Service rate that became effective June 2018increases 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.

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Pepco


The changes in Operating and maintenance expense consisted of the following:
Three Months Ended March 31, 2019Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Baseline    
Labor, other benefits, contracting and materials$(5)$(2) $(14)
Pension and non-pension postretirement benefits expense1
2
 5
Uncollectible accounts expense(2)1
 (4)
Storm-related costs(3)2
 (1)
BSC and PHISCO costs(3)(2) (9)
Other(1)(2) 7
(13)(1) (16)
    
Regulatory required programs1
—
 (3)
Total decrease$(12)$(1) $(19)
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended March 31, 2019Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Depreciation and amortization(a)
$5
$6
 $17
Regulatory required programs(b)
(7)(10) (22)
Total decrease$(2)$(4) $(5)
_________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b)Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

Interest expense, net for the nine months ended September 30, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.
Effective income tax rates were 3.5%4.9% and 6.1%(2.3)% for the three months ended March 31,September 30, 2019 and 2018, respectively, and 4.0% and 3.9% for the nine months ended September 30, 2019 and 2018, respectively. The decreaseincrease is primarily due tothe accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 1412 — 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 March 31, Favorable (Unfavorable) VarianceThree Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2019 2018 2019 2018 2019 2018 
Operating revenues$380
 $384
 $(4)$319
 $328
 $(9) $987
 $1,001
 $(14)
Purchased power and fuel expense164
 177
 13
127
 133
 6
 399
 425
 26
Revenues net of purchased power and fuel expense216
 207
 9
192
 195
 (3) 588
 576
 12
Other operating expenses

 

  

 

   

 

  
Operating and maintenance84
 98
 14
80
 82
 2
 240
 256
 16
Depreciation and amortization46
 45
 (1)46
 47
 1
 138
 135
 (3)
Taxes other than income14
 15
 1
15
 15
 —
 43
 43
 —
Total other operating expenses144
 158
 14
141
 144
 3
 421
 434
 13
Operating income72
 49
 23
51
 51
 —
 167
 142
 25
Other income and (deductions)

 

 



 

 

 

 

 

Interest expense, net(15) (13) (2)(15) (15) —
 (45) (42) (3)
Other, net3
 2
 1
2
 2
 —
 10
 7
 3
Total other income and (deductions)(12) (11) (1)(13) (13) —
 (35) (35) —
Income before income taxes60

38
 22
38

38
 —
 132

107
 25
Income taxes7
 7
 —
5
 5
 —
 16
 17
 1
Net income$53
 $31
 $22
$33
 $33
 $—
 $116
 $90
 $26
Three Months Ended March 31,September 30, 2019 Compared to Three Months Ended March 31,September 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 $22$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 base rates charged to customers in Maryland and Delaware that were put into effectbecame effective throughout 2018 (not reflecting the impact of TCJA), higher transmission basenatural gas distribution rates in Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), and an increase in the highest daily peak load, the absence of a write-offlower write-offs of construction work in progress, lower uncollectible accounts expense, and lower storm costs.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
March 31, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Electric Gas TotalElectric Gas Total Electric Gas Total
Weather$—
 $—
 $—
 $—
 $(2) $(2)
Volume$—
 $1
 $1
—
 (1) (1) —
 1
 1
Distribution4
 (2) 2
1
 —
 1
 3
 —
 3
Regulatory required programs(2) —
 (2)(2) 1
 (1) (6) 1
 (5)
Transmission8
 —
 8
1
 —
 1
 18
 —
 18
Other(3) —
 (3) (3) —
 (3)
Total increase (decrease)$10
 $(1) $9
$(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

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DPL


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. There was no changeDuring the three and nine months ended September 30, 2019 compared to the same period in 2018, RNF related to weather for the three months ended March 31, 2019 compared to same period in 2018.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. There were no cooling degree days in DPL's Delaware electric service territory for the three months ended March 31, 2019 or during the same period in 2018.The changes in heating and cooling degree days in DPL’s Delaware service territory for the three and nine months ended March 31,September 30, 2019 compared to same period in 2018 and normal weather consisted of the following:
Delaware Electric Service Territory    % Change    % Change
Three Months Ended March 31,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Three Months Ended September 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days2,522
 2,504
 2,508
 0.7% 0.6%6
 11
 33
 (45.5)% (81.8)%
Cooling Degree-Days1,043
 1,027
 871
 1.6 % 19.7 %
         
    % Change
Nine Months Ended September 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days2,828
 2,995
 3,017
 (5.6)% (6.3)%
Cooling Degree-Days1,429
 1,376
 1,198
 3.9 % 19.3 %
Delaware Natural Gas Service Territory    % Change    % Change
Three Months Ended March 31,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Three Months Ended September 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days2,522
 2,504
 2,496
 0.7% 1.0%6
 11
 41
 (45.5)% (85.4)%
         
    % Change
Nine Months Ended September 30,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days2,828
 2,995
 3,031
 (5.6)% (6.7)%

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DPL


Volume, exclusive of the effects of weather, remained relatively consistent for the three and nine months ended March 31,September 30, 2019 compared to the same period in 2018.
Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended
March 31,		 % 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 
Residential851
 869
 (2.1)% (1.5)%947
 945
 0.2 % 0.3 % 2,450
 2,485
 (1.4)% (0.6)%
Small commercial & industrial321
 330
 (2.7)% (2.6)%387
 376
 2.9 % 2.5 % 1,013
 1,027
 (1.4)% (1.3)%
Large commercial & industrial810
 829
 (2.3)% (2.2)%924
 973
 (5.0)% (5.2)% 2,600
 2,730
 (4.8)% (4.8)%
Public authorities & electric railroads8
 9
 (11.1)% (7.3)%8
 8
 — % (1.1)% 25
 25
 — % 1.1 %
Total electric retail deliveries(a)
1,990
 2,037
 (2.3)% (2.0)%2,266
 2,302
 (1.6)% (1.7)% 6,088
 6,267
 (2.9)% (2.6)%
As of March 31,As of September 30,
Number of Total Electric Customers (Maryland and Delaware)2019 20182019 2018
Residential464,638
 460,863
466,972
 463,017
Small commercial & industrial61,391
 60,962
61,657
 61,277
Large commercial & industrial1,400
 1,383
1,418
 1,400
Public authorities & electric railroads620
 625
616
 622
Total528,049
 523,833
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.

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DPL


Natural Gas Retail Deliveries to Delaware Customers (in mmcf)Three Months Ended
September 30,		 % Change 
Weather - Normal
% Change(b)
 Nine Months Ended
September 30,		 % Change 
Weather - Normal
% Change(b)
2019 2018   2019 2018  
Residential403
 360
 11.9 % 11.8 % 5,751
 5,801
 (0.9)% 3.8 %
Small commercial & industrial386
 309
 24.9 % 22.9 % 2,972
 2,831
 5.0 % 8.9 %
Large commercial & industrial407
 454
 (10.4)% (10.4)% 1,372
 1,438
 (4.6)% (4.5)%
Transportation1,212
 1,260
 (3.8)% (3.5)% 4,905
 4,893
 0.2 % 1.6 %
Total natural gas deliveries(a)
2,408
 2,383
 1.0 % 1.4 % 15,000
 14,963
 0.2 % 3.3 %
Natural Gas Retail Deliveries to Delaware Customers (in mmcf)Three Months Ended
March 31,		 % Change 
Weather - Normal
% Change(b)
2019 2018  
Residential4,607
 4,485
 2.7% 1.8 %
Small commercial & industrial2,020
 1,878
 7.6% 6.6 %
Large commercial & industrial523
 516
 1.4% 1.4 %
Transportation2,218
 2,213
 0.2% (0.2)%
Total natural gas deliveries(a)
9,368
 9,092
 3.0% 2.3 %
As of March 31,As of September 30,
Number of Delaware Gas Customers2019 2018
Number of Delaware Natural Gas Customers2019 2018
Residential124,575
 123,062
124,944
 123,145
Small commercial & industrial10,023
 9,873
9,885
 9,798
Large commercial & industrial18
 17
18
 19
Transportation157
 155
158
 154
Total134,773
 133,107
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 Revenueincreased for the three and nine months ended March 31,September 30, 2019 compared to the same period in 2018 primarily due to higher electric distribution base rates and higher gas distribution interim base rates charged to customers(not reflecting the impact of TCJA) in Maryland and Delaware that were put into effectbecame effective throughout 2018.2018 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 nine months ended March 31,September 30, 2019 compared to the same period in 2018 primarily due to higher rates effective June 2018rate 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.
See Note 18 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

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DPL


The changes in Operating and maintenance expense consisted of the following:
Three Months Ended March 31, 2019Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Baseline    
Labor, other benefits, contracting and materials$3
$(2) $1
Pension and non-pension postretirement benefits expense1
 3
Uncollectible accounts expense(5)(3) (4)
Storm-related costs(5)2
 (1)
BSC and PHISCO costs(2)(1) (6)
Write-off of construction work in progress(7)
Write-offs of construction work in progress—
 (7)
Other(1)1
 (1)
(17)(2) (15)
    
Regulatory required programs3
—
 (1)
Total decrease$(14)$(2) $(16)
The changes in Depreciation and amortization expense consisted of the following:
 Three Months Ended March 31, 2019
 Increase (Decrease)
Depreciation and amortization(a)
$4
Regulatory required programs(b)
(3)
Total increase$1
 Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
 Increase (Decrease) Increase (Decrease)
Depreciation and amortization(a)
$4
 $11
Regulatory asset amortization(1) (1)
Regulatory required programs(4) (7)
Total increase (decrease)$(1) $3
_________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b)Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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Interest expense, net for the nine months ended September 30, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.
Effective income tax rates were 13.2% and 13.2% for the three months ended March 31,September 30, 2019 and 2018, were 11.7%respectively, and 18.4%,12.1% and 15.9% for the nine months ended September 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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Results of Operations — ACE
Three Months Ended March 31, Favorable (Unfavorable) VarianceThree Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2019 2018 2019 2018 2019 2018 
Operating revenues$273
 $310
 $(37)$419
 $406
 $13
 $966
 $981
 $(15)
Purchased power expense139
 161
 22
210
 198
 (12) 479
 486
 7
Revenues net of purchased power expense134
 149
 (15)209
 208
 1
 487
 495
 (8)
Other operating expenses    
    
     
Operating and maintenance81
 90
 9
86
 85
 (1) 241
 250
 9
Depreciation and amortization31
 33
 2
43
 38
 (5) 114
 107
 (7)
Taxes other than income1
 3
 2
1
 1
 —
 4
 4
 —
Total other operating expenses113
 126
 13
130
 124
 (6) 359
 361
 2
Operating income21
 23
 (2)79
 84
 (5) 128
 134
 (6)
Other income and (deductions)    
    
     
Interest expense, net(14) (16) 2
(15) (16) 1
 (44) (48) 4
Other, net3
 1
 2
1
 1
 —
 5
 2
 3
Total other income and (deductions)(11)
(15) 4
(14)
(15) 1
 (39)
(46) 7
Income before income taxes10

8
 2
65

69
 (4) 89

88
 1
Income taxes—
 1
 1
2
 8
 6
 2
 12
 10
Net income$10
 $7
 $3
$63
 $61
 $2
 $87
 $76
 $11
Three Months Ended March 31,September 30, 2019 Compared to Three Months Ended March 31,September 30, 2018.Net income remained relatively 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 $3$11 million primarily due to increased transmission basehigher electric distribution rates that became effective June 2018April 2019 and higher transmission revenues due to an increase in the transmission rates and the highest daily peak loads,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
March 31, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Weather$(4) $(4)
Volume$(6)(4) (10)
Distribution(3)16
 21
Regulatory required programs(11)(12) (28)
Transmission5
7
 15
Total decrease$(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 nine months ended March 31,September 30, 2019 compared to same period in 2018. due to the impact of unfavorable weather conditions in ACE's service territory.

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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. There were no cooling degree days in ACE’s service territory for the three months ended March 31, 2019 or during the same period in 2018. The changes in heating degree days in ACE’s service territory for the three and nine months ended March 31,September 30, 2019 compared to same period in 2018 consisted of the following:
Heating and Cooling Degree-Days  Normal % Change
Three Months Ended September 30,2019 2018 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days  Normal % Change13
 1
 38
 1,200.0 % (65.8)%
Three Months Ended March 31,2019 2018 2019 vs. 2018 2019 vs. Normal
Cooling Degree-Days980
 1,093
 831
 (10.3)% 17.9 %
         
  Normal % Change
Nine Months Ended September 30,2019 2018 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days2,506
 2,413
 2,489
 3.9% 0.7%2,899
 2,928
 3,080
 (1.0)% (5.9)%
Cooling Degree-Days1,330
 1,447
 1,129
 (8.1)% 17.8 %
Volume,exclusive of the effects of weather, decreased for the three and nine months ended March 31,September 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
March 31,		 % 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 
Residential908
 990
 (8.3)% (8.8)%1,470
 1,548
 (5.0)% (1.6)% 3,182
 3,363
 (5.4)% (3.9)%
Small commercial & industrial310
 314
 (1.3)% (1.3)%431
 442
 (2.5)% (0.5)% 1,055
 1,066
 (1.0)% 0.1 %
Large commercial & industrial791
 824
 (4.0)% (4.1)%938
 1,030
 (8.9)% (7.9)% 2,600
 2,725
 (4.6)% (4.2)%
Public authorities & electric railroads13
 15
 (13.3)% (10.6)%10
 10
 — % (3.9)% 34
 36
 (5.6)% (5.9)%
Total electric retail deliveries(a)
2,022
 2,143
 (5.6)% (5.9)%2,849
 3,030
 (6.0)% (3.7)% 6,871
 7,190
 (4.4)% (3.4)%

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As of March 31,As of September 30,
Number of Electric Customers2019 20182019 2018
Residential491,935
 488,495
493,720
 489,961
Small commercial & industrial61,377
 61,059
61,376
 61,141
Large commercial & industrial3,494
 3,611
3,418
 3,569
Public authorities & electric railroads661
 643
676
 656
Total557,467
 553,808
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 decreasedincreased for the three and nine months ended March 31,September 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 the enactment of TCJA as the result of regulatory settlements. See Note 46 — 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 nine months ended March 31,September 30, 2019 compared to the same period in 2018 primarily due to a rate increase effective June 2018increases and an increase in the highest daily peak loads.

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ACE


Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of other taxes.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
March 31, 2019		Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
Increase (Decrease)Increase (Decrease) Increase (Decrease)
Baseline    
Labor, other benefits, contracting and materials$(4)$2
 $(4)
Uncollectible accounts expense(a)
(5)(3) (9)
Storm-related costs(2)1
 1
BSC and PHISCO costs(2)(1) (4)
Other(6)3
 (4)
(19)2
 (20)
    
Regulatory required programs10
(1) 11
Total decrease$(9)
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 amortizationexpense consisted of the following:
 Three Months Ended
March 31, 2019
 Increase (Decrease)
Depreciation and amortization(a)
$2
Regulatory required programs(b)
(4)
Total decrease$(2)
 Three Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2019
 Increase (Decrease) Increase (Decrease)
Depreciation and amortization(a)
$8
 $19
Regulatory asset amortization(b)
3
 5
Regulatory required programs(6) (17)
Total increase$5
 $7
_________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b)Depreciation andRegulatory asset amortization expenses forincreased primarily due to additional regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.assets related to rate case activity.
Interest expense, net for the nine months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to lower outstanding debt.
Other, net for the nine months ended September 30, 2019 compared to the same period in 2018 increased primarily due to higher income from AFUDC equity.
Effective income tax rates were 0%3.1% and 12.5%11.6% for the three months ended March 31,September 30, 2019 and 2018, respectively and 2.2% and 13.6% for the nine months ended September 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, ComEd, PECO, BGE, Pepco, DPL and ACEthe 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 post-shutdown decommissioning activities report (PSDAR) to the NRC that includes the planned option for decommissioning the site. As of March 31, 2019, across the alternative decommissioning approaches available, Exelon would not be required to post a parental guarantee for TMI or Oyster Creek. 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 additional exemption in order for the plant’s owner(s) to utilize the NDT fund to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by the owner(s). While without reimbursement from or access to the NDT funds. The ultimate amountscosts 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 or future litigation, acrossagreements.


As of September 30, 2019, Exelon would not be required to post a parental guarantee for TMI Unit 1 under the alternativeSAFSTOR scenario which is the planned decommissioning approaches available, ifoption as described in the TMI were to fail to obtain the exemption,Unit 1 PSDAR filed by Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $90 million net of taxes under SAFSTOR. On April 5, 2019, Generation filed with the NRC the TMI PSDAR which details the selection of the SAFSTOR option for

decommissioning the plant.on April 5, 2019. On October 19, 2018,16, 2019, the NRC granted Generation's exemption request to use the Oyster CreekTMI Unit 1 NDT funds for non-radiological decommissioningspent fuel management costs.
On July 31, 2018, Generation entered into an agreement for An additional exemption request would be required to allow the sale of Oyster Creekfunds to be spent on site restoration costs, which isare not expected to occurbe incurred in the second halfnear term.
Project Financing (Exelon and Generation)
Project financing is used to help mitigate risk of 2019.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 3 - Mergers, Acquisitions11 — Debt and DispositionsCredit 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 saleExelon 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 Oyster Creek2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to Holtec.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 threenine months ended March 31,September 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$330
 $236
 $(8) $55
 $32
 $52
 $24
 $22
 $3
$241
 $117
 $21
 $74
 $19
 $76
 $43
 $26
 $11
Add (subtract):                 
Adjustments to reconcile net income to cash:                 
Non-cash operating activities(494) (575) 17
 10
 15
 (38) (15) (16) (8)(399) (293) (35) 12
 15
 (22) 13
 (18) (18)
Pension and non-pension postretirement benefit contributions3
 (16) (29) (1) 5
 49
 3
 —
 6
(15) (31) (30) (1) 5
 51
 1
 (1) 6
Income taxes55
 67
 10
 15
 (6) 13
 7
 10
 (1)(23) 107
 90
 1
 5
 20
 (5) 11
 8
Changes in working capital and other noncurrent assets and liabilities(498) (145) (23) (21) (113) (126) (64) (33) 1
(653) (367) (72) (40) (50) (93) (63) (31) 19
Option premiums received, net33
 33
 —
 —
 —
 —
 —
 —
 —
49
 49
 —
 —
 —
 —
 —
 —
 —
Collateral posted, net113
 127
 (10) —
 (1) —
 —
 —
 —
(476) (520) 53
 —
 (6) —
 —
 —
 —
Net cash flows provided by (used in) operations$(458) $(273) $(43) $58
 $(68) $(50) $(45) $(17) $1
(Decrease) Increase in cash flows from operating activities$(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 threenine months ended March 31,September 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.

•
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 threenine months ended March 31,September 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$7
 $117
 $28
 $(5) $(34) $(100) $(17) $(13) $(65)$238
 $378
 $127
 $(60) $(175) $(18) $20
 $9
 $(53)
Proceeds from NDT fund sales, net106
 106
 —
 —
 —
 —
 —
 —
 —
180
 180
 —
 —
 —
 —
 —
 —
 —
Acquisitions of assets and businesses, net57
 57
 —
 —
 —
 —
 —
 —
 —
Proceeds from sales of assets and businesses(71) (71) —
 —
 —
 —
 —
 —
 —
(73) (73) —
 —
 —
 —
 —
 —
 —
Other investing activities29
 30
 3
 —
 —
 1
 1
 —
 1
(8) (1) 3
 1
 (4) 1
 (1) —
 1
Net cash flows provided by (used in) investing activities$71
 $182
 $31
 $(5) $(34) $(99) $(16) $(13) $(64)
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 threenine months ended March 31,September 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 nine months ended September 30, 2018, Exelon and Generation had proceeds of $79 million relating to the sale of its interest in an electrical contracting business.
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 three months ended March 31, 2018, Exelon and Generation had proceeds of $79 million relating to the sale of its interest in an electrical contracting business.
Capital Expenditure Spending
As of March 31,September 30, 2019, there have been no material changes to the Registrants’ projected capital expenditures as disclosed in Liquidity and Capital Resources of the Exelon 2018 Form 10-K.
Cash Flows from Financing Activities (All Registrants)
The following table provides a summary of the change in cash provided by (used in)flows from financing activities for the threenine months ended March 31,September 30, 2019 and 2018 by Registrant:
Change - Cash Provided by (Used in)Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Increase (Decrease) in cash flows from financing activitiesExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Changes in short-term borrowings, net$(186) $(165) $5
 $(220) $103
 $90
 $31
 $10
 $49
$398
 $—
 $387
 $—
 $42
 $(31) $(66) $273
 $37
Long-term debt, net161
 (20) —
 175
 —
 7
 —
 4
 4
(252) (69) (410) 125
 100
 13
 50
 (196) (116)
Changes in Exelon intercompany money pool—
 (100) —
 (194) —
 (13) —
 —
 —
Changes in intercompany money pool—
 (46) —
 —
 —
 —
 —
 —
 —
Dividends paid on common stock(19) —
 (13) 197
 (4) —
 1
 (5) (3)(56) —
 (35) 32
 (12) —
 (45) (47) (54)
Distributions to member—
 (37) —
 —
 —
 (57) —
 —
 —
—
 14
 —
 —
 —
 (197) —
 —
 —
Contributions from parent/member—
 —
 (50) 145
 —
 19
 14
 —
 5
—
 (54) (200) 103
 86
 46
 44
 (150) 155
Other financing activities55
 3
 —
 5
 —
 —
 —
 —
 —
58
 9
 6
 16
 (5) 1
 1
 3
 (1)
Net cash flows provided by (used in) financing activities$11
 $(319) $(58) $108
 $99
 $46
 $46
 $9
 $55
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 threenine months ended March 31,September 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.
•
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 threenine months ended March 31,September 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
Generation Antelope Valley DOE Nonrecourse Debt 2.33% - 3.56%
 January 5, 2037 12
Generation Kennett Square Capital Lease 7.83% September 20, 2020 3
Generation Continental Wind Nonrecourse Debt 6.00% February 28, 2033 32
Generation Pollution control notes 2.50% March 1, 2019 23
Generation Renewable Power Generation Nonrecourse Debt 4.11% March 31, 2035 10
Generation Energy Efficiency Project Financing 3.46% April 30, 2019 39
Generation ExGen Renewables IV Nonrecourse debt 3mL +3%
 November 30, 2024 38
Generation 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 Antelope Valley DOE Nonrecourse Debt 2.33% - 3.56%
 January 5, 2037 $5
 SolGen Nonrecourse Debt 3.93% September 30, 2036 2
Generation Kennett Square Capital Lease 7.83% September 20, 2020 $1
 Energy Efficiency Project Financing 4.17% August 31, 2019 1
Generation Continental Wind Nonrecourse Debt 6.00% February 28, 2033 $18
 Energy Efficiency Project Financing 3.53% March 31, 2020 1
Generation Pollution control notes 2.50% March 1, 2019 $23
 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
ACE Transition Bonds 5.55% October 20, 2023 $4
 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 $502approximately $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 March 31,September 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 threenine months ended March 31,September 30, 2019 and for the secondthird quarter of 2019 were as follows:
Period Declaration Date Shareholder of Record Date Dividend Payable Date 
Cash per Share(a)
 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
 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
 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 threenine months ended March 31,September 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 firstthird 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 March 31,September 30, 2019, it would have been required to provide incremental collateral of $1.9$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 $4.4$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 March 31,September 30, 2019 and available credit facility capacity prior to any incremental collateral at March 31,September 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$8
 $—
 $997
$10
 $—
 $995
PECO1
 34
 600
—
 28
 600
BGE12
 46
 600
12
 26
 594
Pepco11
 —
 292
10
 —
 290
DPL5
 14
 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 March 31,September 30, 2019, are presented in the following table:
Exelon Intercompany Money Pool During the Three Months Ended March 31, 2019 As of March 31, 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 $467
 $—
 $189
 $260
 $—
 $206
Generation —
 (235) —
 212
 —
 —
PECO 15
 (10) —
 7
 (85) —
BSC —
 (383) (248) —
 (338) (251)
PHI Corporate —
 (9) (1) —
 (10) (10)
PCI 60
 —
 60
 55
 —
 55
PHI Intercompany Money Pool During the Three Months Ended March 31, 2019 As of March 31, 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 $9
 $—
 $—
Pepco 63
 —
 —
DPL —
 (46) —
ACE —
 (29) —
PHISCO 4
 (7) 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 March 31, 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 2019 & 2021 $1,133
 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 400
 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(d)
 NJBPU December 31, 2019 350
 NJBPU December 31, 2019 —
 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 $440 million available in long-term debt refinancing authority and $693 million available in new money long-term debt financing authority from the ICC as of March 31,September 30, 2019 and has an expiration date of June 1, 2019 and August 1, 2021, respectively.
(c)On April 18, 2019, ACE received approval from the NJBPU for $350 million long-term financing authority, expiring on December 31, 2020.2021.


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.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Exelon's hedging program involves the hedging of commodity price risk for Exelon's expected generation, typically on a ratable basis over three-year periods. As of March 31,September 30, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 90%-93%96%-99%, 64%-67%84%-87% and 38%-41%54%-57% for 2019, 2020 and 2021, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including Generation’s sales to the ComEd, PECO and BGE to serve their retail load.
A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5$5 reduction in the annual average around-the-clock energy price based on March 31,September 30, 2019 market conditions and hedged position would be a decrease in pre-tax net incomeimmaterial for 2019, and decreases of approximately $25 million, $279approximately, $88 million and $551$399 million, respectively, for 2019, 2020 and 2021. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation actively manages its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Proprietary Trading Activities
Proprietary trading portfolio activity for the three months ended March 31, 2019 resulted in $4 million of pre-tax gains due to net mark-to-market gains of $2 million and realized gains of $2 million. Generation has not segregated proprietary trading activity within the following discussion because of the relative size of the proprietary trading

portfolio in comparison to Generation’s total Revenue net of purchased power and fuel expense. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Fuel Procurement
Generation procures natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 62%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.
ComEdUtility Registrants
ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers withThere have been no mark-up. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuantsignificant changes or additions to the ICC’s OrderUtility Registrants exposures to commodity price risk that were described in ITEM 1A. RISK FACTORS of Exelon’s 2018 Annual Report on December 19, 2012, ComEd’s commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014.
ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which is further discussed in Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. The block energy contracts are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. ComEd does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, seeForm 10-K. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
PECO, BGE, Pepco, DPL and ACE
PECO, BGE, Pepco, DPL and ACE have contracts to procure electric supply that are executed through a competitive procurement process, which are further discussed in Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. BGE, Pepco, DPL and ACE have certain full requirements contracts, which are considered derivatives and qualifyStatements for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.
PECO, BGE and DPL have also executed derivative natural gas contracts, which either qualify for the normal purchases and normal sales exception or have no mark-to-market balances because the derivatives are index priced, to hedge their long-termadditional information regarding commodity price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their financial statements.
PECO, BGE, Pepco, DPL and ACE do not execute derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.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 March 31,September 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 March 31,September 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 2018 of contracts recorded in results of operations(87) (87) —
Total change in fair value during 2019 of contracts recorded in results of operations(273) (273) —
Reclassification to realized of contracts recorded in results of operations69
 69
 —
215
 215
 —
Changes in fair value — recorded through regulatory assets and liabilities(b)
9
 —
 9
(31) —
 (31)
Changes in allocated collateral135
 135
 —
364
 364
 —
Net option premium paid/(received)(6) (6) —
(13) (13) —
Option premium amortization(37) (37) —
(21) (21) —
Upfront payments and amortizations(c)
(45) (45) —
(73) (73) —
Total mark-to-market energy contract net assets (liabilities) at March 31, 2019(a)
$337
 $577
 $(240)
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 March 31,September 30, 2019, ComEd recorded a regulatory liability of $240$280 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the threenine months ended March 31,September 30, 2019, ComEd also recorded $9$31 million of decreases in fair value and an increase for realized losses due to settlements of $80$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)$(11) $(22) $(1) $(5) $14
 $—
 $(25)$(22) $(105) $(25) $(13) $9
 $9
 $(147)
Prices provided by external sources (Level 2)67
 15
 22
 (1) —
 —
 103
76
 (1) 47
 (10) —
 —
 112
Prices based on model or other valuation methods (Level 3)(c)
152
 210
 36
 (39) (17) (83) 259
65
 442
 116
 33
 (6) (148) 502
Total$208
 $203
 $57
 $(45) $(3) $(83) $337
$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 $492$721 million at March 31,September 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)$(11) $(22) $(1) $(5) $14
 $—
 $(25)$(22) $(105) $(25) $(13) $9
 $9
 $(147)
Prices provided by external sources (Level 2)67
 15
 22
 (1) —
 —
 103
76
 (1) 47
 (10) —
 —
 112
Prices based on model or other valuation methods (Level 3)172
 235
 61
��(14) 9
 36
 499
75
 469
 143
 60
 21
 14
 782
Total$228
 $228
 $82
 $(20) $23
 $36
 $577
$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 $492$721 million at March 31,September 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)$(20) $(25) $(25) $(25) $(26) $(119) $(240)$(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 Collateral and Contingent-Related Features (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the

fair value of contracts at the reporting date. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for detailed discussion of credit risk, collateral and contingent related features.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 March 31,September 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 $36$68 million, $31$30 million, $27$32 million, $37$39 million, $5$15 million and $4$8 million as of March 31,September 30, 2019, respectively.
Rating as of March 31, 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 $819
 $11
 $808
 1
 $135
 $693
 $10
 $683
 $—
 $—
Non-investment grade 86
 39
 47
 

 

 74
 38
 36
 

 

No external ratings                    
Internally rated — investment grade 162
 —
 162
 

 

 297
 1
 296
 

 

Internally rated — non-investment grade 87
 7
 80
 

 

 175
 24
 151
 

 

Total $1,154
 $57
 $1,097
 1
 $135
 $1,239
 $73
 $1,166
 $—
 $—
 Maturity of Credit Risk Exposure Maturity of Credit Risk Exposure
Rating as of March 31, 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 $760
 $47
 $12
 $819
 $649
 $38
 $6
 $693
Non-investment grade 87
 (1) —
 86
 76
 (2) —
 74
No external ratings                
Internally rated — investment grade 110
 26
 26
 162
 234
 35
 28
 297
Internally rated — non-investment grade 76
 5
 6
 87
 148
 16
 11
 175
Total $1,033
 $77
 $44
 $1,154
 $1,107
 $87
 $45
 $1,239
Net Credit Exposure by Type of Counterparty As of
March 31, 2019		 As of
September 30, 2019
Financial institutions $13
 $1
Investor-owned utilities, marketers, power producers 762
 875
Energy cooperatives and municipalities 287
 255
Other 35
 35
Total $1,097
 $1,166
_________
(a)As of March 31,September 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $37$18 million of cash and $19$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.
Collateral (AllCredit-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 ITEM 2. LiquidityNote 13 — Debt and Capital Resources — Credit Matters —Agreements of the Exelon Credit FacilitiesForm 10-K for additional information.
The Utility Registrants
As of March 31,September 30, 2019, ComEd held $11 million in collateral from suppliers in association with energy procurement contracts, $31 million in collateral from suppliers for REC and ZEC contract obligations and $19 million in collateral from suppliers for long-term renewable energy contracts. BGE is not required to post collateral under its electric supply contracts but was holding an immaterial amount of collateral under its electric supply procurement contracts. BGE was not required to post collateral under its natural gas procurement contracts but was holding an immaterial amount of collateral under its natural gas procurement contracts. Pepco and DPL were not required to post collateral under their energy and/or natural gas procurement contracts, but were holding an immaterial amount of collateral under their respective electric supply procurement contracts. PECO and ACEthe Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts.
See Note 6 — Regulatory Matters and Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
RTOs and ISOs (All Registrants)
All Registrants participate in all, or some, of the established wholesale spot energy markets that are administered by PJM, ISO-NE, ISO-NY, CAISO, MISO, SPP, AESO, OIESO and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no spot energy market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot energy markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants.

Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ financial statements.
Exchange Traded Transactions (Exelon, Generation, PHI and DPL)
Generation enters into commodity transactions on NYMEX, ICE, NASDAQ, NGX and the Nodal exchange ("the Exchanges"). DPL enters into commodity transactions on ICE. The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on the Exchanges are significantly collateralized and have limited counterparty credit risk.
Interest Rate and Foreign Exchange Risk (All Registrants)(Exelon and Generation)
The RegistrantsExelon and Generation use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The RegistrantsExelon and Generation may also utilize interest rate swaps to manage their interest rate exposure. At March 31, 2019, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had $619 million of notional amounts of floating-to-fixed hedges outstanding. A hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $1$4 million decrease in Exelon Consolidated pre-tax income for the threenine months ended March 31,September 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 March 31,September 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 policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $587$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 firstthird 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 March 31,September 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.

Beginning January 1, 2019, the Registrants adopted the Leases standard.  As a result of guidance implementation, the Registrants’ Operating lease ROU assets are now included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities in the Consolidated Balance Sheets. The Registrants performed implementation controls, including lease reviews, to adopt the new standard, and implemented certain changes to their ongoing lease processes and control activities, which included enhancements to lease review and valuation processes, new training, and gathering of information for disclosures.
With the exception of the above, there There have been no changes in internal control over financial reporting that occurred during the firstthird 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 March 31,September 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
Amendments to BGE, PECO and PHI Governing Documents
On May 1, 2019, BGE and PECO each adoptedGeneration - Second Amended and Restated Bylaws, and PHI entered into anOperating Agreement
On October 30, 2019, Exelon, as sole member of Generation, executed the Second Amended and Restated Limited Liability Company Agreement. The amendments are primarily intendedOperating Agreement of Generation solely to alignupdate certain administrative provisions, subject to differences required by each Company’s jurisdiction of incorporation or formation. The sole material change effected by BGE’s Amended and Restated Bylaws and PHI’s Amended and Restated Limited Liability Company Agreement is the implementation of a provision whereby effective following the annual election of Directors in 2020, each independent director of the respective company must retire from the Board of Directors at or before the next annual meeting of shareholders following the director’s 75th birthday. The provision further provides that the Board of Directors has full discretion to decline a tendered resignation if it determines, based on the recommendation of the Corporate Governance Committee of the Exelon Board of Directors, that it is in the best interests of the Company and its shareholders to extend the director's continued service for an additional period of time. In addition to the implementation of the same provision, PECO’s Amended and Restated Bylaws also implements a provision declassifying the PECO Board of Directors effective from and after the annual election of directors in 2019, provided that any PECO director who was elected prior to the 2019 annual meeting of shareholders for a term that extends until after the 2019 annual meeting of shareholders shall not be required to stand for election, and shall continue as a director until the annual meeting at which the director’s term expires or until his or her earlier death, resignation or removal.

provisions.  This summary is qualified by reference to the complete text of the BGE and PECOSecond Amended and Restated Bylaws, and the PHI Amended and Restated Limited Liability CompanyOperating Agreement of Generation, attached as ExhibitsExhibit 3.1 3.2 and 3.3, respectively, to this Report.
Appointment of New ComEd Director
On April 26, 2019, the Board of Directors of ComEd appointed Mr. Juan Ochoa to the Board to fill a vacancy created by an expansion of the size of the Board. Mr. Ochoa is not being appointed to any committees and will receive the standard compensation paid by ComEd to its outside directors, as disclosed in ComEd’s most recent Information Statement in Schedule 14C.
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 BylawsOperating Agreement of Baltimore Gas and ElectricExelon Generation Company, LLC
  
3.24.1
AmendedOne Hundred and Restated BylawsSeventeenth Supplemental Indenture dated as of August 15, 2019 from PECO Energy Company to U.S. Bank National Association, as trustee (File No. 000-16844, Form 8-K dated September 10, 2019)
  
3.34.2
AmendedIndenture, dated as of September 1, 2019, between Baltimore Gas and Restated Limited LiabilityElectric Company Agreement of Pepco Holdings LLCand U.S. Bank National Association, as trustee (File No. 001-01910, Form 8-K dated September 12, 2019, Exhibit 4.1)
  
4.110.1*
Supplemental Indenture datedExelon Corporation Non-Employee Director Deferred Stock Unit Plan, as of February 7, 2019 from Commonwealth Edison Company to BNY Mellon Trust Company of Illinois, as trustee,amended and D. G. Donovan, as co-trustee (File No. 001-01839, Form 8-K dated February 19, 2019, Exhibit 4.1)restated effective September 25, 2019.
  
4.210.2*
One HundredAmended Form of Restricted Stock Award Agreement under Exelon Corporation Long-Term Incentive Plan
10.3*
Exelon Corporation Employee Stock Purchase Plan, as amended and Twenty-Second Supplemental Indenture, dated April 3, 2019, between Delmarva Power & Light Companyrestated effective September 25, 2019.
10.4*
Exelon Corporation Employee Stock Purchase Plan for Unincorporated Subsidiaries, as amended and The Bank of New York Mellon,restated effective September 25, 2019.
10.5*
Exelon Corporation Stock Deferral Plan, as trusteeamended 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 LabelsLabel 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 March 31,September 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 March 31,September 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)
  
May 2,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)
  
May 2,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)
  
May 2,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)
  
May 2,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)
  
May 2,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)
  
May 2,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)		  
May 2,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)		  
May 2,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)		  
May 2,October 31, 2019


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