UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2018March 31, 2019
or
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission
File Number
 Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number IRS Employer Identification Number
     
1-16169 EXELON CORPORATION 23-2990190
  
(a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago, Illinois 60680-5379
(800) 483-3220
  
     
333-85496 EXELON GENERATION COMPANY, LLC 23-3064219
  
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348-2473
(610) 765-5959
  
     
1-1839 COMMONWEALTH EDISON COMPANY 36-0938600
  
(an Illinois corporation)
440 South LaSalle Street
Chicago, Illinois 60605-1028
(312) 394-4321
  
     
000-16844 PECO ENERGY COMPANY 23-0970240
  
(a Pennsylvania corporation)
P.O. Box 8699
2301 Market Street
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000
  
     
1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
  
(a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore, Maryland 21201-3708
(410) 234-5000
  
     
001-31403 PEPCO HOLDINGS LLC 52-2297449
  
(a Delaware limited liability company)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000
  
     
001-01072 POTOMAC ELECTRIC POWER COMPANY 53-0127880
  
(a District of Columbia and Virginia corporation)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000
  
     
001-01405 DELMARVA POWER & LIGHT COMPANY 51-0084283
  
(a Delaware and Virginia corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000

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

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
EXELON CORPORATION;
Common Stock, without par valueEXCNew York and Chicago
Series A Junior Debt Subordinated DebenturesEXC22New York
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 CompanyEXC/28New York

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  x  No  o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  x  No  o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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



    
Exelon Generation Company, LLC



x    
Commonwealth Edison Company



x    
PECO Energy Company



x    
Baltimore Gas and Electric Company



x    
Pepco Holdings LLC    x    
Potomac Electric Power Company    x    
Delmarva Power & Light Company    x    
Atlantic City Electric Company    x    
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  o  No  x
The number of shares outstanding of each registrant’s common stock as of June 30, 2018March 31, 2019 was:
Exelon Corporation Common Stock, without par value965,906,701970,954,879
Exelon Generation Company, LLCnot applicable
Commonwealth Edison Company Common Stock, $12.50 par value127,021,285127,021,331
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
98
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
98
WHERE TO FIND MORE INFORMATION
98
PART I.
FINANCIAL INFORMATION
109
ITEM 1.
FINANCIAL STATEMENTS
109
 
Exelon Corporation
 
 
Consolidated Statements of Operations and Comprehensive Income
1110
 
Consolidated Statements of Cash Flows
1211
 
Consolidated Balance Sheets
1312
 
Consolidated StatementStatements of Changes in Shareholders’ Equity
1514
 
Exelon Generation Company, LLC
 
 
Consolidated Statements of Operations and Comprehensive Income
1615
 
Consolidated Statements of Cash Flows
1716
 
Consolidated Balance Sheets
1817
 
Consolidated StatementStatements of Changes in Equity
2019
 
Commonwealth Edison Company
 
 
Consolidated Statements of Operations and Comprehensive Income
2120
 
Consolidated Statements of Cash Flows
2221
 
Consolidated Balance Sheets
2322
 
Consolidated StatementStatements of Changes in Shareholders' Equity
2524
 
PECO Energy Company
 
 
Consolidated Statements of Operations and Comprehensive Income
2625
 
Consolidated Statements of Cash Flows
2726
 
Consolidated Balance Sheets
2827
 
Consolidated StatementStatements of Changes in Shareholder's Equity
3029
 
Baltimore Gas and Electric Company
 
 
Consolidated Statements of Operations and Comprehensive Income
30
Statements of Cash Flows
31
 
Consolidated Statements of Cash FlowsBalance Sheets
32
 
Consolidated Balance Sheets
33
Consolidated StatementStatements of Changes in Shareholders’Shareholder's Equity
3534
 
Pepco Holdings LLC
 
 
Consolidated Statements of Operations and Comprehensive Income
3635
 
Consolidated Statements of Cash Flows
3736
 
Consolidated Balance Sheets
3837
 
Consolidated StatementStatements of Changes in Equity
4039

 Page No.
 
Potomac Electric Power Company
 
 
Statements of Operations and Comprehensive Income
4140
 
Statements of Cash Flows
4241
 
Balance Sheets
4342
 
StatementStatements of Changes in Shareholder's Equity
4544
 
Delmarva Power & Light Company
 
 
Statements of Operations and Comprehensive Income
4645
 
Statements of Cash Flows
4746
 
Balance Sheets
4847
 
StatementStatements of Changes in Shareholder’s Equity
5049
 
Atlantic City Electric Company
 
 
Consolidated Statements of Operations and Comprehensive Income
5150
 
Consolidated Statements of Cash Flows
5251
 
Consolidated Balance Sheets
5352
 
Consolidated StatementStatements of Changes in Shareholder’s Equity
5554
 
Combined Notes to Consolidated Financial Statements
5655
 
1. Significant Accounting Policies
5756
 
2. New Accounting StandardsVariable Interest Entities
6258
 
3. Variable Interest EntitiesMergers, Acquisitions and Dispositions
63
4. Revenue from Contracts with Customers
64
 
4. Mergers, Acquisitions and Dispositions5. Leases
69
5. Revenue from Contracts with Customers
7266
 
6. Regulatory Matters
7569
 
7. Impairment of Long-Lived Assets
9273
 
8. Early Plant Retirements
9373
 
9. Fair Value of Financial Assets and Liabilities
9776
 
10. Derivative Financial Instruments
11993
 
11. Debt and Credit Agreements
136103
 
12. Income Taxes
137105
 
13. Nuclear Decommissioning
144107
 
14. Retirement Benefits
147108
 
15. Changes in Accumulated Other Comprehensive Income
150110
 
16. Earnings Per ShareCommitments and EquityContingencies
155113
 
17. Commitments and ContingenciesSupplemental Financial Information
156120
 
18. Supplemental Financial Information
167
19. Segment Information
174
20. Subsequent Events
188126

 Page No.
ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
190135
 
Exelon Corporation
190135
 
Executive Overview
190135
 
Financial Results of Operations
192136
 
Significant 20182019 Transactions and Developments
200137
 
Exelon's Strategy and Outlook for 2018 and Beyond
205140
 
Liquidity Considerations
207141
 
Other Key Business Drivers and Management Strategies
208142
 
Critical Accounting Policies and Estimates
214147
 
Results of Operations By Registrant
216147
 
Exelon Generation Company, LLC
217148
 
Commonwealth Edison Company
227153
 
PECO Energy Company
234156
 
Baltimore Gas and Electric Company
241160
 
Pepco Holdings LLC
248163
 
Potomac Electric Power Company
251164
 
Delmarva Power & Light Company
258167
 
Atlantic City Electric Company
266171
 
Liquidity and Capital Resources
272174
 
Contractual Obligations and Off-Balance Sheet Arrangements
287180
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
288181
ITEM 4.
CONTROLS AND PROCEDURES
296187
PART II.
OTHER INFORMATION
297188
ITEM 1.
LEGAL PROCEEDINGS
297188
ITEM 1A.
RISK FACTORS
297188
ITEM 4.
MINE SAFETY DISCLOSURES
297188
ITEM 5.
OTHER INFORMATION
188
ITEM 6.
EXHIBITS
298189
SIGNATURES
301192
 
Exelon Corporation
301192
 
Exelon Generation Company, LLC
302193
 
Commonwealth Edison Company
303194
 
PECO Energy Company
304195
 
Baltimore Gas and Electric Company
305196
 
Pepco Holdings LLC
306197
 
Potomac Electric Power Company
307198
 
Delmarva Power & Light Company
308199
 
Atlantic City Electric Company
309200

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon Exelon Corporation
Generation Exelon Generation Company, LLC
ComEd Commonwealth Edison Company
PECO PECO Energy Company
BGE Baltimore Gas and Electric Company
Pepco Holdings or PHI Pepco Holdings LLC (formerly Pepco Holdings, Inc.)
Pepco Potomac Electric Power Company
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
Legacy PHIPHI, 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
ConectivConectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE
ConEdison SolutionsThe competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc., a subsidiary of Consolidated Edison, Inc.
Constellation Constellation Energy Group, Inc.
EEDCExelon Energy Delivery Company, LLC
EGR IV ExGen Renewables IV, LLC
EGTPEGRP ExGen Texas Power, LLC
EntergyEntergy Nuclear FitzPatrick,Renewables Partners, LLC
Exelon Corporate Exelon in its corporate capacity as a holding company
Exelon Transmission CompanyExelon Transmission Company, LLC
Exelon WindExelon Wind, LLC and Exelon Generation Acquisition Company, LLC
FitzPatrick James A. FitzPatrick nuclear generating station
PCI Potomac Capital Investment Corporation and its subsidiaries
PEC L.P.PECO Energy Capital, L.P.
PECO Trust IIIPECO Capital Trust III
PECO Trust IVPECO Energy Capital Trust IV
Pepco Energy Services or PES Pepco Energy Services, Inc. and its subsidiaries
PHI Corporate PHI in its corporate capacity as a holding company
PHISCO PHI Service Company
RPGRenewable Power Generation
SolGen SolGen, LLC
TMIThree Mile Island nuclear facility

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations  
TMIThree Mile Island nuclear facility
UIIUnicom Investments, Inc.
Note “—”"—" of the Exelon 20172018 Form 10-K Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 20172018 Annual Report on Form 10-K
AECAlternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source
AESO Alberta Electric Systems Operator
AFUDC Allowance for Funds Used During Construction
AGEAlbany Green Energy Project
AMI Advanced Metering Infrastructure
AMPAdvanced Metering Program
AOCI Accumulated Other Comprehensive Income
ARC Asset Retirement Cost
ARO Asset Retirement Obligation
ARPAlternative Revenue Program
BGS Basic Generation Service
CAISO California Independent System Operator
CAPCustomer Assistance Program
CCGTsCombined-Cycle Gas Turbines
CERCLAComprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CES Clean Energy Standard
Clean Air Act Clean Air Act of 1963, as amended
Clean Water Act Federal Water Pollution Control Amendments of 1972, as amended
Conectiv EnergyCODM Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010
CSAPRCross-State Air Pollution RuleChief 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 District of Columbia Public Service Commission
Default Electricity SupplyThe supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or Basic Generation Service
DOE United States Department of Energy
DOEE Department of Energy & Environment
DOJ United States Department of Justice
DPSC Delaware Public Service Commission
DRPDirect Stock Purchase and Dividend Reinvestment Plan
DSP Default Service Provider
EDF Electricite de France SA and its subsidiaries

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
EE&CEnergy Efficiency and Conservation/Demand Response
EIMA Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EmPower A Maryland demand-side management program for Pepco and DPL
EPA United States Environmental Protection Agency
EPSA Electric Power Supply Association
ERCOT Electric Reliability Council of Texas
ERISAEmployee Retirement Income Security Act of 1974, as amended
EROAExpected Rate of Return on Assets
ESPPEmployee Stock Purchase Plan
FASB Financial Accounting Standards Board
FEJA Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC Federal Energy Regulatory Commission
FRCC Florida Reliability Coordinating Council
GAAP Generally Accepted Accounting Principles in the United States
GCR Gas Cost Rate
GHG Greenhouse Gas
GSA Generation Supply Adjustment
GWhGigawatt hour
IBEW International Brotherhood of Electrical Workers
ICC Illinois Commerce Commission
ICE Intercontinental Exchange

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Illinois EPA Illinois Environmental Protection Agency
Illinois Settlement Legislation Legislation enacted in 2007 affecting electric utilities in Illinois
IPA Illinois Power Agency
IRC Internal Revenue Code
IRS Internal Revenue Service
ISO Independent System Operator
ISO-NE Independent System Operator New England Inc.
ISO-NY Independent System Operator New York
kVKilovolt
kWKilowatt
kWhKilowatt-hour
LIBOR London Interbank Offered Rate
LLRWLow-Level Radioactive Waste
LT PlanLong-term renewable resources procurement plan
LTIPLong-Term Incentive Plan
MAPPMid-Atlantic Power Pathway
MATS U.S. EPA Mercury and Air Toxics Rule
MBR Market Based Rates Incentive

Table of Contents

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

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
POLR Provider of Last Resort
POR Purchase of Receivables
PPA Power Purchase Agreement
Price-Anderson Act Price-Anderson Nuclear Industries Indemnity Act of 1957

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
PRP Potentially Responsible Parties
PSEG Public Service Enterprise Group Incorporated
PVPhotovoltaic
RCRA Resource Conservation and Recovery Act of 1976, as amended
REC Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement Units Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RESRetail Electric Suppliers
RFPRequest for Proposal
Rider Reconcilable Surcharge Recovery Mechanism
RMC Risk Management Committee
ROE Return on equity
RPMROU PJM Reliability Pricing ModelRight-of-use
RPS Renewable Energy Portfolio Standards
RSSA Reliability Support Services Agreement
RTEPRegional Transmission Expansion Plan
RTO Regional Transmission Organization
S&P Standard & Poor’s Ratings Services
SEC United States Securities and Exchange Commission
SERC SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SILOSale-In, Lease-Out
SNF Spent Nuclear Fuel
SOS Standard Offer Service
SPFPASecurity, Police and Fire Professionals of America
SPP Southwest Power Pool
TCJA Tax Cuts and Jobs Act
Transition Bond Charge Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds 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

Table of Contents

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 20172018 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 23,22, 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, 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 17,16, 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 public may readSEC maintains an Internet site at www.sec.gov that contains reports, proxy and copy any reports orinformation statements, and other information that the Registrants file electronically with the SEC at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.SEC. These documents are also available to the public from commercial document retrieval services the website maintained by the SEC at www.sec.gov and the Registrants’ websitesRegistrants' website at www.exeloncorp.com. Information contained on the Registrants’ websitesRegistrants' website shall not be deemed incorporated into, or to be a part of, this Report.

Table of Contents




PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

Table of Contents


EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions, except per share data)2018 2017 2018 2017
Operating revenues       
Competitive businesses revenues$4,305
 $3,950
 $9,417
 $8,500
Rate-regulated utility revenues3,797
 3,657
 8,368
 7,776
Revenues from alternative revenue programs(26) 58
 (16) 137
Total operating revenues8,076
 7,665
 17,769
 16,413
Operating expenses       
Competitive businesses purchased power and fuel2,277
 2,158
 5,566
 4,952
Rate-regulated utility purchased power and fuel1,038
 928
 2,476
 2,033
Operating and maintenance2,307
 2,945
 4,691
 5,383
Depreciation and amortization1,088
 915
 2,179
 1,811
Taxes other than income428
 420
 874
 857
Total operating expenses7,138

7,366

15,786

15,036
Gain on sales of assets and businesses4
 1
 60
 5
Bargain purchase gain—
 —
 —
 226
Operating income942

300

2,043

1,608
Other income and (deductions)       
Interest expense, net(367) (426) (732) (789)
Interest expense to affiliates(6) (10) (13) (20)
Other, net44
 177
 17
 434
Total other income and (deductions)(329)
(259)
(728)
(375)
Income before income taxes613
 41
 1,315
 1,233
Income taxes66
 (62) 125
 149
Equity in losses of unconsolidated affiliates(5) (9) (11) (18)
Net income542

94

1,179

1,066
Net income (loss) attributable to noncontrolling interests3
 (1) 54
 (20)
Net income attributable to common shareholders$539

$95

$1,125

$1,086
Comprehensive income, net of income taxes       
Net income$542
 $94
 $1,179
 $1,066
Other comprehensive income (loss), net of income taxes       
Pension and non-pension postretirement benefit plans:       
Prior service benefit reclassified to periodic benefit cost(17) (14) (33) (28)
Actuarial loss reclassified to periodic benefit cost61
 49
 123
 98
Pension and non-pension postretirement benefit plan valuation adjustment(1) (2) 18
 (58)
Unrealized gain (loss) on cash flow hedges4
 (1) 12
 5
Unrealized gain on investments in unconsolidated affiliates2
 —
 3
 3
Unrealized (loss) gain on foreign currency translation(5) 2
 (6) 3
Unrealized gain on marketable securities—
 1
 —
 2
Other comprehensive income (loss)44

35

117

25
Comprehensive income586

129

1,296

1,091
Comprehensive income (loss) attributable to noncontrolling interests4
 (1) 56
 (22)
Comprehensive income attributable to common shareholders$582
 $130
 $1,240
 $1,113
        
Average shares of common stock outstanding:       
Basic967
 934
 967
 931
Diluted969
 936
 968
 932
Earnings per average common share:       
Basic$0.56
 $0.10
 $1.16
 $1.17
Diluted$0.56
 $0.10
 $1.16
 $1.17
Dividends declared per common share$0.35
 $0.33
 $0.69
 $0.66

 Three Months Ended
March 31,
(In millions, except per share data)2019 2018
Operating revenues   
Competitive businesses revenues$4,979
 $5,113
Rate-regulated utility revenues4,503
 4,570
Revenues from alternative revenue programs(5) 10
Total operating revenues9,477
 9,693
Operating expenses   
Competitive businesses purchased power and fuel3,204
 3,289
Rate-regulated utility purchased power and fuel1,349
 1,438
Operating and maintenance2,189
 2,384
Depreciation and amortization1,075
 1,091
Taxes other than income445
 446
Total operating expenses8,262

8,648
Gain on sales of assets and businesses3
 56
Operating income1,218

1,101
Other income and (deductions)
 
Interest expense, net(397) (365)
Interest expense to affiliates(6) (6)
Other, net467
 (28)
Total other income and (deductions)64

(399)
Income before income taxes1,282
 702
Income taxes310
 59
Equity in losses of unconsolidated affiliates(6) (7)
Net income966

636
Net income attributable to noncontrolling interests59
 51
Net income attributable to common shareholders$907

$585
Comprehensive income, net of income taxes   
Net income$966
 $636
Other comprehensive (loss) income, net of income taxes   
Pension and non-pension postretirement benefit plans:   
Prior service benefit reclassified to periodic benefit cost(16) (17)
Actuarial loss reclassified to periodic benefit cost36
 61
Pension and non-pension postretirement benefit plan valuation adjustment(38) 18
Unrealized gain on cash flow hedges—
 8
Unrealized (loss) gain on investments in unconsolidated affiliates(2) 1
Unrealized gain on foreign currency translation2
 1
Other comprehensive (loss) income(18)
72
Comprehensive income948

708
Comprehensive income attributable to noncontrolling interests58
 52
Comprehensive income attributable to common shareholders$890
 $656
    
Average shares of common stock outstanding:   
Basic971
 966
Assumed exercise and/or distributions of stock-based awards1
 2
Diluted(a)
972
 968
    
Earnings per average common share:   
Basic$0.93
 $0.61
Diluted$0.93
 $0.60
Table of Contents__________
(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 months ended March 31, 2019 and approximately 5 million for the three months ended March 31, 2018.

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 Six Months Ended
June 30,
(In millions)2018 2017
Cash flows from operating activities   
Net income$1,179
 $1,066
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization3,000
 2,591
Impairment of long-lived assets and losses on regulatory assets41
 445
Gain on sales of assets and businesses(60) (5)
Bargain purchase gain—
 (226)
Deferred income taxes and amortization of investment tax credits(2) 113
Net fair value changes related to derivatives151
 230
Net realized and unrealized losses (gains) on nuclear decommissioning trust fund investments80
 (284)
Other non-cash operating activities479
 415
Changes in assets and liabilities:   
Accounts receivable(105) 301
Inventories60
 (23)
Accounts payable and accrued expenses(342) (810)
Option premiums paid, net(36) (8)
Collateral received (posted), net81
 (173)
Income taxes129
 58
Pension and non-pension postretirement benefit contributions(345) (325)
Other assets and liabilities(441) (470)
Net cash flows provided by operating activities3,869

2,895
Cash flows from investing activities   
Capital expenditures(3,807) (3,845)
Proceeds from nuclear decommissioning trust fund sales3,822
 5,213
Investment in nuclear decommissioning trust funds(3,924) (5,339)
Acquisition of assets and businesses, net(57) (212)
Proceeds from sales of assets and businesses89
 211
Other investing activities31
 (9)
Net cash flows used in investing activities(3,846)
(3,981)
Cash flows from financing activities   
Changes in short-term borrowings200
 422
Proceeds from short-term borrowings with maturities greater than 90 days126
 576
Repayments on short-term borrowings with maturities greater than 90 days(1) (510)
Issuance of long-term debt1,488
 981
Retirement of long-term debt(1,309) (1,049)
Dividends paid on common stock(666) (607)
Common stock issued from treasury stock—
 1,150
Proceeds from employee stock plans27
 43
Other financing activities(50) (23)
Net cash flows (used in) provided by financing activities(185)
983
Decrease in cash, cash equivalents and restricted cash(162) (103)
Cash, cash equivalents and restricted cash at beginning of period1,190
 914
Cash, cash equivalents and restricted cash at end of period$1,028

$811

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Cash flows from operating activities   
Net income$966
 $636
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
Impairment of long-lived assets7
 —
Gain on sales of assets and businesses—
 (56)
Deferred income taxes and amortization of investment tax credits187
 (14)
Net fair value changes related to derivatives31
 259
Net realized and unrealized (gains) losses on NDT funds(308) 68
Other non-cash operating activities127
 240
Changes in assets and liabilities:   
Accounts receivable79
 133
Inventories128
 167
Accounts payable and accrued expenses(764) (451)
Option premiums received (paid), net6
 (27)
Collateral posted, net(101) (214)
Income taxes141
 86
Pension and non-pension postretirement benefit contributions(328) (331)
Other assets and liabilities(587) (495)
Net cash flows provided by operating activities1,044

1,502
Cash flows from investing activities   
Capital expenditures(1,873) (1,880)
Proceeds from NDT fund sales3,713
 1,189
Investment in NDT funds(3,666) (1,248)
Proceeds from sales of assets and businesses8
 79
Other investing activities32
 3
Net cash flows used in investing activities(1,786)
(1,857)
Cash flows from financing activities   
Changes in short-term borrowings540
 726
Proceeds from short-term borrowings with maturities greater than 90 days—
 1
Repayments on short-term borrowings with maturities greater than 90 days—
 (1)
Issuance of long-term debt402
 1,130
Retirement of long-term debt(352) (1,241)
Dividends paid on common stock(352) (333)
Proceeds from employee stock plans51
 12
Other financing activities(14) (30)
Net cash flows provided by financing activities275

264
Decrease in cash, cash equivalents and restricted cash(467) (91)
Cash, cash equivalents and restricted cash at beginning of period1,781
 1,190
Cash, cash equivalents and restricted cash at end of period$1,314

$1,099

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017
ASSETS   
Current assets   
Cash and cash equivalents$694
 $898
Restricted cash and cash equivalents206
 207
Accounts receivable, net   
Customer4,094
 4,445
Other1,407
 1,132
Mark-to-market derivative assets799
 976
Unamortized energy contract assets46
 60
Inventories, net   
Fossil fuel and emission allowances270
 340
Materials and supplies1,320
 1,311
Regulatory assets1,293
 1,267
Other1,360
 1,260
Total current assets11,489

11,896
Property, plant and equipment, net75,284
 74,202
Deferred debits and other assets   
Regulatory assets8,023
 8,021
Nuclear decommissioning trust funds13,110
 13,272
Investments636
 640
Goodwill6,677
 6,677
Mark-to-market derivative assets457
 337
Unamortized energy contract assets379
 395
Other1,194
 1,330
Total deferred debits and other assets30,476

30,672
Total assets(a)
$117,249

$116,770

Table of Contents
(In millions)March 31, 2019 December 31, 2018
ASSETS   
Current assets   
Cash and cash equivalents$880
 $1,349
Restricted cash and cash equivalents223
 247
Accounts receivable, net   
Customer4,564
 4,607
Other1,062
 1,256
Mark-to-market derivative assets652
 804
Unamortized energy contract assets49
 48
Inventories, net   
Fossil fuel and emission allowances179
 334
Materials and supplies1,380
 1,351
Regulatory assets1,191
 1,222
Assets held for sale890
 904
Other1,406
 1,238
Total current assets12,476

13,360
Property, plant and equipment, net77,460
 76,707
Deferred debits and other assets   
Regulatory assets8,222
 8,237
Nuclear decommissioning trust funds12,302
 11,661
Investments620
 625
Goodwill6,677
 6,677
Mark-to-market derivative assets454
 452
Unamortized energy contract assets365
 372
Other3,017
 1,575
Total deferred debits and other assets31,657

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

$119,666

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017March 31, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY      
Current liabilities      
Short-term borrowings$1,252
 $929
$1,254
 $714
Long-term debt due within one year1,158
 2,088
2,508
 1,349
Accounts payable3,113
 3,532
3,327
 3,800
Accrued expenses1,665
 1,837
1,725
 2,112
Payables to affiliates5
 5
5
 5
Regulatory liabilities701
 523
522
 644
Mark-to-market derivative liabilities268
 232
345
 475
Unamortized energy contract liabilities171
 231
151
 149
Renewable energy credit obligation257
 352
348
 344
PHI merger related obligation63
 87
Liabilities held for sale799
 777
Other973
 982
1,245
 1,035
Total current liabilities9,626
 10,798
12,229
 11,404
Long-term debt33,179
 32,176
32,960
 34,075
Long-term debt to financing trusts389
 389
390
 390
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits11,484
 11,235
11,642
 11,330
Asset retirement obligations10,222
 10,029
9,967
 9,679
Pension obligations3,412
 3,736
3,734
 3,988
Non-pension postretirement benefit obligations2,132
 2,093
1,984
 1,928
Spent nuclear fuel obligation1,157
 1,147
1,178
 1,171
Regulatory liabilities9,677
 9,865
9,781
 9,559
Mark-to-market derivative liabilities507
 409
434
 479
Unamortized energy contract liabilities538
 609
432
 463
Other2,087
 2,097
3,158
 2,130
Total deferred credits and other liabilities41,216
 41,220
42,310
 40,727
Total liabilities(a)
84,410

84,583
87,889

86,596
Commitments and contingencies
 

 
Shareholders’ equity      
Common stock (No par value, 2,000 shares authorized, 966 shares and 963 shares outstanding at June 30, 2018 and December 31, 2017, respectively)19,008
 18,964
Treasury stock, at cost (2 shares at June 30, 2018 and December 31, 2017)(123) (123)
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)
Retained earnings14,551
 14,081
15,321
 14,766
Accumulated other comprehensive loss, net(2,921) (3,026)(3,012) (2,995)
Total shareholders’ equity30,515

29,896
31,357

30,764
Noncontrolling interests2,324
 2,291
2,347
 2,306
Total equity32,839

32,187
33,704

33,070
Total liabilities and shareholders’ equity$117,249

$116,770
$121,593

$119,666
__________
(a)Exelon’s consolidated assets include $9,612$9,546 million and $9,597$9,667 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,544$3,572 million and $3,618$3,548 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 32 — Variable Interest Entities for additional information.

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTSTATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Three Months Ended March 31, 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, 2017965,168
 $18,964
 $(123) $14,081
 $(3,026) $2,291
 $32,187
Balance, December 31, 2018970,020
 $19,116
 $(123) $14,766
 $(2,995) $2,306
 $33,070
Net income—
 —
 —
 1,125
 —
 54
 1,179
—
 —
 —
 907
 —
 59
 966
Long-term incentive plan activity1,868
 17
 —
 —
 —
 —
 17
2,446
 (3) —
 —
 —
 —
 (3)
Employee stock purchase plan issuances703
 27
 —
 —
 —
 —
 27
320
 51
 —
 —
 —
 —
 51
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 (23) (23)—
 —
 —
 —
 —
 (17) (17)
Common stock dividends—
 —
 —
 (669) —
 —
 (669)
Sale of noncontrolling interests—
 7
 —
 —
 —
 —
 7
Common stock dividends
($0.36/common share)

—
 —
 —
 (352) —
 —
 (352)
Other comprehensive income, net of income taxes—
 —
 —
 —
 115
 2
 117
—
 —
 —
 —
 (17) (1) (18)
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 —
 —
 14
 (10) —
 4
Balance, June 30, 2018967,739
 $19,008
 $(123) $14,551
 $(2,921) $2,324
 $32,839
Balance, March 31, 2019972,786
 $19,171
 $(123) $15,321
 $(3,012) $2,347
 $33,704

Table of Contents

 Three Months Ended March 31, 2018
(In millions, shares
in thousands)
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
Net income—
 —
 —
 585
 —
 51
 636
Long-term incentive plan activity1,685
 (3) —
 —
 —
 —
 (3)
Employee stock purchase plan issuances361
 12
 —
 —
 —
 —
 12
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 (9) (9)
Common stock dividends
($0.35/common share)

—
 —
 —
 (334) —
 —
 (334)
Other comprehensive income, net of income taxes—
 —
 —
 —
 71
 1
 72
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 —
 —
 14
 (10) —
 4
Balance, March 31, 2018967,214
 $18,973
 $(123) $14,346
 $(2,965) $2,334
 $32,565

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions)2018 2017 2018 2017
Operating revenues       
Operating revenues$4,306
 $3,948
 $9,419
 $8,495
Operating revenues from affiliates273
 268
 671
 598
Total operating revenues4,579

4,216

10,090

9,093
Operating expenses       
Purchased power and fuel2,277
 2,156
 5,566
 4,952
Purchased power and fuel from affiliates3
 1
 7
 3
Operating and maintenance1,247
 1,826
 2,425
 3,138
Operating and maintenance from affiliates171
 186
 331
 365
Depreciation and amortization466
 334
 914
 637
Taxes other than income134
 140
 272
 282
Total operating expenses4,298

4,643

9,515

9,377
Gain on sales of assets and businesses1
 —
 54
 4
Bargain purchase gain—
 —
 —
 226
Operating income (loss)282

(427)
629

(54)
Other income and (deductions)       
Interest expense, net(93) (120) (184) (209)
Interest expense to affiliates(9) (9) (18) (19)
Other, net29
 181
 (15) 440
Total other income and (deductions)(73)
52

(217)
212
Income (loss) before income taxes209
 (375) 412
 158
Income taxes23
 (148) 32
 (25)
Equity in losses of unconsolidated affiliates(5) (9) (12) (19)
Net income (loss)181

(236)
368

164
Net income (loss) attributable to noncontrolling interests3
 (1) 54
 (20)
Net income (loss) attributable to membership interest$178

$(235)
$314

$184
Comprehensive income, net of income taxes       
Net income (loss)$181
 $(236) $368
 $164
Other comprehensive income (loss), net of income taxes       
Unrealized gain (loss) on cash flow hedges5
 (1) 12
 5
Unrealized gain on investments in unconsolidated affiliates2
 —
 3
 4
Unrealized (loss) gain on foreign currency translation(5) 2
 (6) 3
Other comprehensive income2

1

9

12
Comprehensive income (loss)183

(235)
377

176
Comprehensive income (loss) attributable to noncontrolling interests4
 (1) 56
 (22)
Comprehensive income (loss) attributable to membership interest$179
 $(234) $321
 $198

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Operating revenues   
Operating revenues$4,979
 $5,114
Operating revenues from affiliates317
 398
Total operating revenues5,296

5,512
Operating expenses   
Purchased power and fuel3,204
 3,289
Purchased power and fuel from affiliates1
 4
Operating and maintenance1,068
 1,178
Operating and maintenance from affiliates150
 161
Depreciation and amortization405
 448
Taxes other than income135
 138
Total operating expenses4,963

5,218
Gain on sales of assets and businesses—
 53
Operating income333

347
Other income and (deductions)   
Interest expense, net(102) (91)
Interest expense to affiliates(9) (10)
Other, net430
 (44)
Total other income and (deductions)319

(145)
Income before income taxes652
 202
Income taxes224
 9
Equity in losses of unconsolidated affiliates(6) (7)
Net income422

186
Net income attributable to noncontrolling interests59
 50
Net income attributable to membership interest$363

$136
Comprehensive income, net of income taxes   
Net income$422
 $186
Other comprehensive income (loss), net of income taxes   
Unrealized gain on cash flow hedges1
 7
Unrealized (loss) gain on investments in unconsolidated affiliates(2) 1
Unrealized gain (loss) on foreign currency translation2
 (1)
Other comprehensive income1

7
Comprehensive income423

193
Comprehensive income attributable to noncontrolling interests58
 51
Comprehensive income attributable to membership interest$365
 $142

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 Six Months Ended
June 30,
(In millions)2018 2017
Cash flows from operating activities   
Net income$368
 $164
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization1,735
 1,415
Impairment of long-lived assets41
 445
Gain on sales of assets and businesses(54) (4)
Bargain purchase gain—
 (226)
Deferred income taxes and amortization of investment tax credits(149) (167)
Net fair value changes related to derivatives158
 235
Net realized and unrealized losses (gains) on nuclear decommissioning trust fund investments80
 (284)
Other non-cash operating activities85
 121
Changes in assets and liabilities:
 
Accounts receivable258
 151
Receivables from and payables to affiliates, net7
 8
Inventories34
 (5)
Accounts payable and accrued expenses(272) (327)
Option premiums paid, net(36) (8)
Collateral received (posted), net91
 (163)
Income taxes58
 (99)
Pension and non-pension postretirement benefit contributions(129) (116)
Other assets and liabilities(212) (166)
Net cash flows provided by operating activities2,063

974
Cash flows from investing activities   
Capital expenditures(1,298) (1,189)
Proceeds from nuclear decommissioning trust fund sales3,822
 5,213
Investment in nuclear decommissioning trust funds(3,924) (5,339)
Acquisition of assets and businesses, net(57) (212)
Proceeds from sales of assets and businesses89
 210
Changes in Exelon intercompany money pool(185) —
Other investing activities4
 (32)
Net cash flows used in investing activities(1,549)
(1,349)
Cash flows from financing activities   
Changes in short-term borrowings—
 (51)
Proceeds from short-term borrowings with maturities greater than 90 days1
 76
Repayments of short-term borrowings with maturities greater than 90 days(1) (10)
Issuance of long-term debt13
 779
Retirement of long-term debt(76) (295)
Changes in Exelon intercompany money pool(54) 196
Distributions to member(377) (330)
Other financing activities(24) (7)
Net cash flows (used in) provided by financing activities(518)
358
Decrease in cash, cash equivalents and restricted cash(4) (17)
Cash, cash equivalents and restricted cash at beginning of period554
 448
Cash, cash equivalents and restricted cash at end of period$550

$431

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Cash flows from operating activities   
Net income$422
 $186
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
Impairment of long-lived assets7
 —
Gain on sales of assets and businesses—
 (53)
Deferred income taxes and amortization of investment tax credits108
 (68)
Net fair value changes related to derivatives33
 264
Net realized and unrealized (gains) losses on NDT funds(308) 68
Other non-cash operating activities(90) 45
Changes in assets and liabilities:
 
Accounts receivable197
 194
Receivables from and payables to affiliates, net(5) (15)
Inventories103
 122
Accounts payable and accrued expenses(411) (317)
Option premiums received (paid), net6
 (27)
Collateral posted, net(87) (214)
Income taxes146
 79
Pension and non-pension postretirement benefit contributions(141) (125)
Other assets and liabilities(187) (142)
Net cash flows provided by operating activities582

855
Cash flows from investing activities   
Capital expenditures(511) (628)
Proceeds from NDT fund sales3,713
 1,189
Investment in NDT funds(3,666) (1,248)
Proceeds from sales of assets and businesses8
 79
Other investing activities23
 (7)
Net cash flows used in investing activities(433)
(615)
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
Retirement of long-term debt(47) (29)
Changes in Exelon intercompany money pool(100) —
Distributions to member(225) (188)
Other financing activities(6) (9)
Net cash flows used in financing activities(376)
(57)
(Decrease) increase in cash, cash equivalents and restricted cash(227) 183
Cash, cash equivalents and restricted cash at beginning of period903
 554
Cash, cash equivalents and restricted cash at end of period$676

$737

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017
ASSETS   
Current assets   
Cash and cash equivalents$420
 $416
Restricted cash and cash equivalents130
 138
Accounts receivable, net   
Customer2,435
 2,697
Other276
 321
Mark-to-market derivative assets799
 976
Receivables from affiliates146
 140
Unamortized energy contract assets46
 60
Inventories, net   
Fossil fuel and emission allowances214
 264
Materials and supplies953
 937
Other1,148
 933
Total current assets6,567

6,882
Property, plant and equipment, net24,479
 24,906
Deferred debits and other assets   
Nuclear decommissioning trust funds13,110
 13,272
Investments423
 433
Goodwill47
 47
Mark-to-market derivative assets457
 334
Prepaid pension asset1,522
 1,502
Unamortized energy contract assets378
 395
Deferred income taxes6
 16
Other679
 670
Total deferred debits and other assets16,622

16,669
Total assets(a)
$47,668

$48,457

Table of Contents
(In millions)March 31, 2019 December 31, 2018
ASSETS   
Current assets   
Cash and cash equivalents$537
 $750
Restricted cash and cash equivalents139
 153
Accounts receivable, net   
Customer2,800
 2,941
Other367
 562
Mark-to-market derivative assets652
 804
Receivables from affiliates163
 173
Unamortized energy contract assets49
 49
Inventories, net   
Fossil fuel and emission allowances146
 251
Materials and supplies965
 963
Assets held for sale890
 904
Other1,013
 883
Total current assets7,721

8,433
Property, plant and equipment, net24,034
 23,981
Deferred debits and other assets   
Nuclear decommissioning trust funds12,302
 11,661
Investments404
 414
Goodwill47
 47
Mark-to-market derivative assets454
 452
Prepaid pension asset1,525
 1,421
Unamortized energy contract assets364
 371
Deferred income taxes18
 21
Other1,813
 755
Total deferred debits and other assets16,927

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

$47,556

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017March 31, 2019 December 31, 2018
LIABILITIES AND EQUITY      
Current liabilities      
Short-term borrowings$—
 $2
Long-term debt due within one year321
 346
$2,365
 $906
Accounts payable1,264
 1,773
1,566
 1,847
Accrued expenses976
 1,022
675
 898
Payables to affiliates128
 123
136
 139
Borrowings from Exelon intercompany money pool—
 54
—
 100
Mark-to-market derivative liabilities245
 211
318
 449
Unamortized energy contract liabilities36
 43
28
 31
Renewable energy credit obligation257
 352
348
 343
Liabilities held for sale799
 777
Other295
 265
425
 279
Total current liabilities3,522
 4,191
6,660
 5,769
Long-term debt7,661
 7,734
5,487
 6,989
Long-term debt to affiliate904
 910
Long-term debt to affiliates895
 898
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits3,673
 3,811
3,502
 3,383
Asset retirement obligations10,037
 9,844
9,737
 9,450
Non-pension postretirement benefit obligations907
 916
894
 900
Spent nuclear fuel obligation1,157
 1,147
1,178
 1,171
Payables to affiliates2,916
 3,065
2,870
 2,606
Mark-to-market derivative liabilities270
 174
219
 252
Unamortized energy contract liabilities34
 48
16
 20
Other648
 658
1,528
 610
Total deferred credits and other liabilities19,642
 19,663
19,944
 18,392
Total liabilities(a)
31,729
 32,498
32,986
 32,048
Commitments and contingencies
 

 
Equity      
Member’s equity      
Membership interest9,357
 9,357
9,525
 9,518
Undistributed earnings4,292
 4,349
3,862
 3,724
Accumulated other comprehensive loss, net(33) (37)(36) (38)
Total member’s equity13,616
 13,669
13,351
 13,204
Noncontrolling interests2,323
 2,290
2,345
 2,304
Total equity15,939
 15,959
15,696
 15,508
Total liabilities and equity$47,668
 $48,457
$48,682
 $47,556
__________
(a)Generation’s consolidated assets include $9,575$9,515 million and $9,556$9,634 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,456$3,508 million and $3,516$3,480 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 32 — Variable Interest Entities for additional information.

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTSTATEMENTS OF CHANGES IN EQUITY
(Unaudited)
Three Months Ended March 31, 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, 2017$9,357
 $4,349
 $(37) $2,290
 $15,959
Balance, December 31, 2018$9,518
 $3,724
 $(38) $2,304
 $15,508
Net income—
 314
 —
 54
 368
—
 363
 —
 59
 422
Changes in equity of noncontrolling interests—
 —
 —
 (23) (23)—
 —
 —
 (17) (17)
Sale of noncontrolling interests7
 —
 —
 —
 7
Distributions to member—
 (377) —
 —
 (377)—
 (225) —
 —
 (225)
Other comprehensive income, net of income taxes—
 —
 7
 2
 9
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 6
 (3) —
 3
Balance, June 30, 2018$9,357

$4,292

$(33)
$2,323

$15,939
Other comprehensive income (loss), net of income taxes—
 —
 2
 (1) 1
Balance, March 31, 2019$9,525

$3,862

$(36)
$2,345

$15,696

Table of Contents
 Three Months Ended March 31, 2018
 Member’s Equity    
(In millions)
Membership
Interest
 
Undistributed
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 Total Equity
Balance, December 31, 2017$9,357
 $4,349
 $(37) $2,290
 $15,959
Net income—
 136
 —
 50
 186
Changes in equity of noncontrolling interests—
 —
 —
 (9) (9)
Distributions to member—
 (188) —
 —
 (188)
Other comprehensive income, net of income taxes—
 —
 6
 1
 7
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 6
 (3) —
 3
Balance, March 31, 2018$9,357
 $4,303
 $(34) $2,332
 $15,958


COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions)2018 2017 2018 2017
Operating revenues       
Electric operating revenues$1,410
 $1,336
 $2,903
 $2,615
Revenues from alternative revenue programs(17) 18
 (12) 32
Operating revenues from affiliates5
 3
 19
 9
Total operating revenues1,398

1,357

2,910

2,656
Operating expenses       
Purchased power373
 360
 784
 689
Purchased power from affiliate104
 18
 298
 24
Operating and maintenance255
 312
 509
 620
Operating and maintenance from affiliate69
 65
 129
 127
Depreciation and amortization231
 211
 459
 419
Taxes other than income79
 72
 156
 144
Total operating expenses1,111

1,038

2,335

2,023
Gain on sales of assets1
 —
 5
 —
Operating income288

319

580

633
Other income and (deductions)       
Interest expense, net(82) (98) (168) (179)
Interest expense to affiliates(3) (3) (7) (6)
Other, net4
 4
 12
 8
Total other income and (deductions)(81)
(97)
(163)
(177)
Income before income taxes207
 222
 417
 456
Income taxes43
 104
 88
 197
Net income$164

$118

$329

$259
Comprehensive income$164
 $118
 $329
 $259

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Operating revenues   
Electric operating revenues$1,432
 $1,493
Revenues from alternative revenue programs(28) 5
Operating revenues from affiliates4
 14
Total operating revenues1,408

1,512
Operating expenses   
Purchased power388
 411
Purchased power from affiliate97
 194
Operating and maintenance259
 253
Operating and maintenance from affiliate62
 60
Depreciation and amortization251
 228
Taxes other than income78
 77
Total operating expenses1,135

1,223
Gain on sales of assets3
 3
Operating income276

292
Other income and (deductions)   
Interest expense, net(84) (86)
Interest expense to affiliates(3) (3)
Other, net8
 8
Total other income and (deductions)(79)
(81)
Income before income taxes197
 211
Income taxes40
 46
Net income$157

$165
Comprehensive income$157
 $165

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 Six Months Ended
June 30,
(In millions)2018 2017
Cash flows from operating activities   
Net income$329
 $259
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization459
 419
Deferred income taxes and amortization of investment tax credits84
 235
Other non-cash operating activities117
 58
Changes in assets and liabilities:   
Accounts receivable(133) 12
Receivables from and payables to affiliates, net15
 (4)
Inventories5
 (2)
Accounts payable and accrued expenses(41) (182)
Collateral posted, net(13) (8)
Income taxes(15) 4
Pension and non-pension postretirement benefit contributions(39) (37)
Other assets and liabilities(166) 34
Net cash flows provided by operating activities602

788
Cash flows from investing activities   
Capital expenditures(1,026) (1,168)
Other investing activities17
 12
Net cash flows used in investing activities(1,009)
(1,156)
Cash flows from financing activities   
Changes in short-term borrowings320
 389
Issuance of long-term debt800
 —
Retirement of long-term debt(700) —
Contributions from parent225
 184
Dividends paid on common stock(229) (211)
Other financing activities(10) (1)
Net cash flows provided by financing activities406

361
Decrease in cash, cash equivalents and restricted cash(1) (7)
Cash, cash equivalents and restricted cash at beginning of period144
 58
Cash, cash equivalents and restricted cash at end of period$143

$51

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Cash flows from operating activities   
Net income$157
 $165
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization251
 228
Deferred income taxes and amortization of investment tax credits34
 50
Other non-cash operating activities56
 46
Changes in assets and liabilities:   
Accounts receivable14
 39
Receivables from and payables to affiliates, net(34) (19)
Inventories(3) 5
Accounts payable and accrued expenses(188) (158)
Collateral posted, net(13) (3)
Income taxes5
 (5)
Pension and non-pension postretirement benefit contributions(67) (38)
Other assets and liabilities(121) (176)
Net cash flows provided by operating activities91

134
Cash flows from investing activities   
Capital expenditures(503) (531)
Other investing activities11
 8
Net cash flows used in investing activities(492)
(523)
Cash flows from financing activities   
Changes in short-term borrowings322
 317
Issuance of long-term debt400
 800
Retirement of long-term debt(300) (700)
Contributions from parent63
 113
Dividends paid on common stock(127) (114)
Other financing activities(9) (9)
Net cash flows provided by financing activities349

407
(Decrease) increase in cash, cash equivalents and restricted cash(52) 18
Cash, cash equivalents and restricted cash at beginning of period330
 144
Cash, cash equivalents and restricted cash at end of period$278

$162

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017
ASSETS   
Current assets   
Cash and cash equivalents$30
 $76
Restricted cash5
 5
Accounts receivable, net   
Customer579
 559
Other376
 266
Receivables from affiliates21
 13
Inventories, net146
 152
Regulatory assets237
 225
Other86
 68
Total current assets1,480

1,364
Property, plant and equipment, net21,323
 20,723
Deferred debits and other assets   
Regulatory assets1,134
 1,054
Investments6
 6
Goodwill2,625
 2,625
Receivables from affiliates2,430
 2,528
Prepaid pension asset1,130
 1,188
Other318
 238
Total deferred debits and other assets7,643

7,639
Total assets$30,446

$29,726

Table of Contents
(In millions)March 31, 2019 December 31, 2018
ASSETS   
Current assets   
Cash and cash equivalents$68
 $135
Restricted cash17
 29
Accounts receivable, net   
Customer539
 539
Other336
 320
Receivables from affiliates21
 20
Inventories, net152
 148
Regulatory assets285
 293
Other89
 86
Total current assets1,507

1,570
Property, plant and equipment, net22,274
 22,058
Deferred debits and other assets   
Regulatory assets1,338
 1,307
Investments6
 6
Goodwill2,625
 2,625
Receivables from affiliates2,412
 2,217
Prepaid pension asset1,073
 1,035
Other347
 395
Total deferred debits and other assets7,801

7,585
Total assets$31,582

$31,213

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017
LIABILITIES AND SHAREHOLDERS’ EQUITY   
Current liabilities   
Short-term borrowings$320
 $—
Long-term debt due within one year440
 840
Accounts payable547
 568
Accrued expenses285
 327
Payables to affiliates97
 74
Customer deposits111
 112
Regulatory liabilities287
 249
Mark-to-market derivative liability23
 21
Other81
 103
Total current liabilities2,191
 2,294
Long-term debt7,255
 6,761
Long-term debt to financing trust205
 205
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits3,597
 3,469
Asset retirement obligations111
 111
Non-pension postretirement benefits obligations210
 219
Regulatory liabilities6,221
 6,328
Mark-to-market derivative liability229
 235
Other560
 562
Total deferred credits and other liabilities10,928
 10,924
Total liabilities20,579
 20,184
Commitments and contingencies
 
Shareholders’ equity   
Common stock1,588
 1,588
Other paid-in capital7,047
 6,822
Retained deficit unappropriated(1,639) (1,639)
Retained earnings appropriated2,871
 2,771
Total shareholders’ equity9,867
 9,542
Total liabilities and shareholders’ equity$30,446
 $29,726

Table of Contents
(In millions)March 31, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY   
Current liabilities   
Short-term borrowings$322
 $—
Long-term debt due within one year—
 300
Accounts payable491
 607
Accrued expenses229
 373
Payables to affiliates74
 119
Customer deposits112
 111
Regulatory liabilities241
 293
Mark-to-market derivative liability27
 26
Other98
 96
Total current liabilities1,594
 1,925
Long-term debt8,194
 7,801
Long-term debt to financing trust205
 205
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits3,870
 3,813
Asset retirement obligations119
 118
Non-pension postretirement benefits obligations196
 201
Regulatory liabilities6,269
 6,050
Mark-to-market derivative liability213
 223
Other582
 630
Total deferred credits and other liabilities11,249
 11,035
Total liabilities21,242
 20,966
Commitments and contingencies
 
Shareholders’ equity   
Common stock1,588
 1,588
Other paid-in capital7,385
 7,322
Retained deficit unappropriated(1,639) (1,639)
Retained earnings appropriated3,006
 2,976
Total shareholders’ equity10,340
 10,247
Total liabilities and shareholders’ equity$31,582
 $31,213

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTSTATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
(In millions)
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
Net income—
 —
 329
 —
 329
Appropriation of retained earnings for future dividends—
 —
 (329) 329
 —
Common stock dividends—
 —
 —
 (229) (229)
Contributions from parent—
 225
 —
 —
 225
Balance, June 30, 2018$1,588

$7,047

$(1,639)
$2,871

$9,867

Table of Contents

 Three Months Ended March 31, 2019
(In millions)
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
Net income—
 —
 157
 —
 157
Appropriation of retained earnings for future dividends—
 —
 (157) 157
 —
Common stock dividends—
 —
 —
 (127) (127)
Contributions from parent—
 63
 —
 —
 63
Balance, March 31, 2019$1,588

$7,385

$(1,639)
$3,006

$10,340
          
          
 Three Months Ended March 31, 2018
(In millions)
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
Net income—
 —
 165
 —
 165
Appropriation of retained earnings for future dividends—
 —
 (165) 165
 —
Common stock dividends—
 —
 —
 (114) (114)
Contributions from parent—
 113
 —
 —
 113
Balance, March 31, 2018$1,588
 $6,935
 $(1,639) $2,822
 $9,706

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions)2018 2017 2018 2017
Operating revenues       
Electric operating revenues$556
 $548
 $1,189
 $1,138
Natural gas operating revenues93
 80
 325
 285
Revenues from alternative revenue programs2
 —
 1
 —
Operating revenues from affiliates2
 2
 3
 3
Total operating revenues653

630

1,518

1,426
Operating expenses       
Purchased power161
 136
 361
 292
Purchased fuel37
 27
 134
 113
Purchased power from affiliate24
 34
 60
 79
Operating and maintenance153
 153
 387
 326
Operating and maintenance from affiliates38
 37
 79
 72
Depreciation and amortization74
 71
 149
 141
Taxes other than income39
 35
 79
 74
Total operating expenses526

493

1,249

1,097
Operating income127

137

269

329
Other income and (deductions)       
Interest expense, net(28) (28) (57) (56)
Interest expense to affiliates(4) (3) (7) (6)
Other, net—
 2
 2
 3
Total other income and (deductions)(32)
(29)
(62)
(59)
Income before income taxes95
 108
 207

270
Income taxes(1) 20
 (3) 55
Net income$96

$88

$210

$215
Comprehensive income$96
 $88
 $210
 $215

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Operating revenues   
Electric operating revenues$622
 $633
Natural gas operating revenues280
 232
Revenues from alternative revenue programs(3) (1)
Operating revenues from affiliates1
 2
Total operating revenues900

866
Operating expenses   
Purchased power152
 199
Purchased fuel135
 98
Purchased power from affiliate44
 36
Operating and maintenance187
 233
Operating and maintenance from affiliates38
 42
Depreciation and amortization81
 75
Taxes other than income41
 41
Total operating expenses678

724
Operating income222

142
Other income and (deductions)   
Interest expense, net(30) (30)
Interest expense to affiliates(3) (3)
Other, net4
 2
Total other income and (deductions)(29)
(31)
Income before income taxes193

111
Income taxes25
 (2)
Net income$168

$113
Comprehensive income$168
 $113

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 Six Months Ended
June 30,
(In millions)2018 2017
Cash flows from operating activities   
Net income$210
 $215
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization149
 141
Deferred income taxes and amortization of investment tax credits(10) 39
Other non-cash operating activities22
 22
Changes in assets and liabilities:   
Accounts receivable(43) 26
Receivables from and payables to affiliates, net(4) (10)
Inventories4
 7
Accounts payable and accrued expenses(18) (30)
Income taxes19
 51
Pension and non-pension postretirement benefit contributions(25) (23)
Other assets and liabilities(50) (70)
Net cash flows provided by operating activities254

368
Cash flows from investing activities   
Capital expenditures(411) (367)
Changes in Exelon intercompany money pool—
 121
Other investing activities5
 4
Net cash flows used in investing activities(406)
(242)
Cash flows from financing activities   
Changes in short-term borrowings50
 —
Issuance of long-term debt375
 —
Retirement of long-term debt(500) —
Changes in Exelon intercompany money pool233
 —
Contributions from parent41
 —
Dividends paid on common stock(293) (144)
Other financing activities(6) —
Net cash flows used in financing activities(100)
(144)
Decrease in cash, cash equivalents and restricted cash(252) (18)
Cash, cash equivalents and restricted cash at beginning of period275
 67
Cash, cash equivalents and restricted cash at end of period$23

$49

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Cash flows from operating activities   
Net income$168
 $113
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization81
 75
Deferred income taxes and amortization of investment tax credits5
 (4)
Other non-cash operating activities16
 21
Changes in assets and liabilities:   
Accounts receivable(86) (51)
Receivables from and payables to affiliates, net7
 7
Inventories23
 12
Accounts payable and accrued expenses(13) 6
Income taxes20
 5
Pension and non-pension postretirement benefit contributions(25) (24)
Other assets and liabilities(119) (141)
Net cash flows provided by operating activities77

19
Cash flows from investing activities   
Capital expenditures(222) (217)
Other investing activities2
 2
Net cash flows used in investing activities(220)
(215)
Cash flows from financing activities   
Changes in short-term borrowings—
 220
Issuance of long-term debt—
 325
Retirement of long-term debt—
 (500)
Changes in Exelon intercompany money pool—
 194
Contributions from parent145
 —
Dividends paid on common stock(90) (287)
Other financing activities—
 (5)
Net cash flows provided by (used in) financing activities55

(53)
Decrease in cash, cash equivalents and restricted cash(88) (249)
Cash, cash equivalents and restricted cash at beginning of period135
 275
Cash, cash equivalents and restricted cash at end of period$47

$26

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017
ASSETS   
Current assets   
Cash and cash equivalents$18
 $271
Restricted cash and cash equivalents5
 4
Accounts receivable, net   
Customer285
 327
Other178
 105
Receivable from affiliates—
 —
Inventories, net   
Fossil fuel24
 31
Materials and supplies33
 30
Prepaid utility taxes72
 8
Regulatory assets75
 29
Other25
 17
Total current assets715

822
Property, plant and equipment, net8,307
 8,053
Deferred debits and other assets   
Regulatory assets427
 381
Investments25
 25
Receivable from affiliates485
 537
Prepaid pension asset355
 340
Other31
 12
Total deferred debits and other assets1,323

1,295
Total assets$10,345

$10,170

Table of Contents
(In millions)March 31, 2019 December 31, 2018
ASSETS   
Current assets   
Cash and cash equivalents$41
 $130
Restricted cash and cash equivalents6
 5
Accounts receivable, net   
Customer394
 321
Other148
 151
Inventories, net   
Fossil fuel15
 38
Materials and supplies37
 37
Prepaid utility taxes100
 —
Regulatory assets54
 81
Other21
 19
Total current assets816

782
Property, plant and equipment, net8,766
 8,610
Deferred debits and other assets   
Regulatory assets491
 460
Investments25
 25
Receivable from affiliates457
 389
Prepaid pension asset372
 349
Other29
 27
Total deferred debits and other assets1,374

1,250
Total assets$10,956

$10,642

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Short-term borrowings$50
 $—
Long-term debt due within one year—
 500
Accounts payable349
 370
Accrued expenses118
 114
Payables to affiliates48
 53
Borrowings from Exelon intercompany money pool233
 —
Customer deposits67
 66
Regulatory liabilities168
 141
Other32
 23
Total current liabilities1,065
 1,267
Long-term debt2,773
 2,403
Long-term debt to financing trusts184
 184
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits1,854
 1,789
Asset retirement obligations27
 27
Non-pension postretirement benefits obligations288
 288
Regulatory liabilities545
 549
Other74
 86
Total deferred credits and other liabilities2,788
 2,739
Total liabilities6,810
 6,593
Commitments and contingencies
 
Shareholder’s equity   
Common stock2,530
 2,489
Retained earnings1,005
 1,087
Accumulated other comprehensive income, net—
 1
Total shareholder’s equity3,535
 3,577
Total liabilities and shareholder's equity$10,345
 $10,170

Table of Contents
(In millions)March 31, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Accounts payable379
 370
Accrued expenses119
 113
Payables to affiliates66
 59
Customer deposits68
 68
Regulatory liabilities123
 175
Other32
 24
Total current liabilities787
 809
Long-term debt3,084
 3,084
Long-term debt to financing trusts184
 184
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits1,974
 1,933
Asset retirement obligations27
 27
Non-pension postretirement benefits obligations288
 288
Regulatory liabilities488
 421
Other81
 76
Total deferred credits and other liabilities2,858
 2,745
Total liabilities6,913
 6,822
Commitments and contingencies
 
Shareholder’s equity   
Common stock2,723
 2,578
Retained earnings1,320
 1,242
Total shareholder’s equity4,043
 3,820
Total liabilities and shareholder's equity$10,956
 $10,642

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTSTATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
(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—
 210
 —
 210
Common stock dividends—
 (293) —
 (293)
Contributions from parent41
 —
 —
 41
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 1
 (1) —
Balance, June 30, 2018$2,530

$1,005

$—

$3,535

Table of Contents

 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 AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions)2018 2017 2018 2017
Operating revenues       
Electric operating revenues$542
 $545
 $1,196
 $1,186
Natural gas operating revenues118
 94
 448
 365
Revenues from alternative revenue programs(4) 32
 (17) 66
Operating revenues from affiliates6
 3
 12
 8
Total operating revenues662

674

1,639

1,625
Operating expenses       
Purchased power135
 115
 327
 248
Purchased fuel32
 22
 155
 105
Purchased power from affiliate62
 97
 127
 231
Operating and maintenance135
 135
 318
 284
Operating and maintenance from affiliates41
 39
 79
 73
Depreciation and amortization114
 112
 248
 239
Taxes other than income59
 56
 124
 119
Total operating expenses578

576

1,378

1,299
Gain on sales of assets1
 —
 1
 —
Operating income85

98

262

326
Other income and (deductions)       
Interest expense, net(25) (22) (51) (46)
Interest expense to affiliates—
 (4) —
 (8)
Other, net4
 4
 9
 8
Total other income and (deductions)(21)
(22)
(42)
(46)
Income before income taxes64
 76
 220

280
Income taxes13
 31
 41
 111
Net income$51

$45

$179

$169
Comprehensive income$51
 $45
 $179
 $169

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Operating revenues   
Electric operating revenues$652
 $654
Natural gas operating revenues308
 330
Revenues from alternative revenue programs10
 (13)
Operating revenues from affiliates6
 6
Total operating revenues976

977
Operating expenses   
Purchased power190
 192
Purchased fuel95
 123
Purchased power from affiliate75
 65
Operating and maintenance153
 184
Operating and maintenance from affiliates39
 37
Depreciation and amortization136
 134
Taxes other than income68
 65
Total operating expenses756

800
Operating income220

177
Other income and (deductions)   
Interest expense, net(29) (25)
Other, net5
 4
Total other income and (deductions)(24)
(21)
Income before income taxes196

156
Income taxes36
 28
Net income$160

$128
Comprehensive income$160
 $128

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 Six Months Ended
June 30,
(In millions)2018 2017
Cash flows from operating activities   
Net income$179
 $169
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization248
 239
Deferred income taxes and amortization of investment tax credits39
 99
Other non-cash operating activities27
 35
Changes in assets and liabilities:   
Accounts receivable73
 77
Receivables from and payables to affiliates, net(4) (7)
Inventories5
 (5)
Accounts payable and accrued expenses(48) (83)
Income taxes(45) 26
Pension and non-pension postretirement benefit contributions(49) (47)
Other assets and liabilities39
 (34)
Net cash flows provided by operating activities464

469
Cash flows from investing activities   
Capital expenditures(434) (405)
Other investing activities6
 4
Net cash flows used in investing activities(428)
(401)
Cash flows from financing activities   
Changes in short-term borrowings59
 40
Retirement of long-term debt—
 (41)
Dividends paid on common stock(105) (99)
Net cash flows used in financing activities(46)
(100)
Decrease in cash, cash equivalents and restricted cash(10) (32)
Cash, cash equivalents and restricted cash at beginning of period18
 50
Cash, cash equivalents and restricted cash at end of period$8

$18

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Cash flows from operating activities   
Net income$160
 $128
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization136
 134
Deferred income taxes and amortization of investment tax credits28
 22
Other non-cash operating activities27
 20
Changes in assets and liabilities:   
Accounts receivable(39) (32)
Receivables from and payables to affiliates, net(10) —
Inventories17
 20
Accounts payable and accrued expenses(27) (9)
Collateral posted, net(1) —
Income taxes8
 14
Pension and non-pension postretirement benefit contributions(40) (45)
Other assets and liabilities(14) 61
Net cash flows provided by operating activities245

313
Cash flows from investing activities   
Capital expenditures(258) (224)
Other investing activities1
 1
Net cash flows used in investing activities(257)
(223)
Cash flows from financing activities   
Changes in short-term borrowings71
 (32)
Dividends paid on common stock(56) (52)
Net cash flows provided by (used in) financing activities15

(84)
Increase in cash, cash equivalents and restricted cash3
 6
Cash, cash equivalents and restricted cash at beginning of period13
 18
Cash, cash equivalents and restricted cash at end of period$16

$24

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017
ASSETS   
Current assets   
Cash and cash equivalents$7
 $17
Restricted cash and cash equivalents1
 1
Accounts receivable, net   
Customer300
 375
Other89
 94
Receivables from affiliates—
 1
Inventories, net   
Gas held in storage27
 37
Materials and supplies45
 40
Prepaid utility taxes—
 69
Regulatory assets185
 174
Other4
 3
Total current assets658

811
Property, plant and equipment, net7,864
 7,602
Deferred debits and other assets   
Regulatory assets405
 397
Investments6
 5
Prepaid pension asset302
 285
Other6
 4
Total deferred debits and other assets719

691
Total assets$9,241

$9,104

Table of Contents
(In millions)March 31, 2019 December 31, 2018
ASSETS   
Current assets   
Cash and cash equivalents$12
 $7
Restricted cash and cash equivalents4
 6
Accounts receivable, net   
Customer385
 353
Other89
 90
Receivables from affiliates—
 1
Inventories, net   
Fossil fuel16
 36
Materials and supplies42
 39
Prepaid utility taxes38
 74
Regulatory assets161
 177
Other6
 3
Total current assets753

786
Property, plant and equipment, net8,408
 8,243
Deferred debits and other assets   
Regulatory assets395
 398
Investments5
 5
Prepaid pension asset301
 279
Other105
 5
Total deferred debits and other assets806

687
Total assets$9,967

$9,716

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017March 31, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY      
Current liabilities      
Short-term borrowings$136
 $77
$106
 $35
Accounts payable249
 265
291
 295
Accrued expenses95
 164
142
 155
Payables to affiliates48
 52
54
 65
Customer deposits120
 116
120
 120
Regulatory liabilities106
 62
67
 77
Other23
 24
54
 27
Total current liabilities777
 760
834
 774
Long-term debt2,578
 2,577
2,876
 2,876
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits1,306
 1,244
1,275
 1,222
Asset retirement obligations23
 23
24
 24
Non-pension postretirement benefits obligations199
 202
198
 201
Regulatory liabilities1,070
 1,101
1,172
 1,192
Other73
 56
130
 73
Total deferred credits and other liabilities2,671
 2,626
2,799
 2,712
Total liabilities6,026
 5,963
6,509
 6,362
Commitments and contingencies
 

 
Shareholders’ equity      
Common stock1,605
 1,605
1,714
 1,714
Retained earnings1,610
 1,536
1,744
 1,640
Total shareholders' equity3,215
 3,141
3,458
 3,354
Total liabilities and shareholders’ equity$9,241
 $9,104
$9,967
 $9,716


Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTSTATEMENTS OF CHANGES IN SHAREHOLDERS’SHAREHOLDER'S EQUITY
(Unaudited)
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholders’
Equity
Balance, December 31, 2017$1,605
 $1,536
 $3,141
Net income—
 179
 179
Common stock dividends—
 (105) (105)
Balance, June 30, 2018$1,605

$1,610

$3,215

Table of Contents

 Three Months Ended March 31, 2019
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholders’
Equity
Balance, December 31, 2018$1,714
 $1,640
 $3,354
Net income—
 160
 160
Common stock dividends—
 (56) (56)
Balance, March 31, 2019$1,714

$1,744
 $3,458
      
 Three Months Ended March 31, 2018
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholders’
Equity
Balance, December 31, 2017$1,605
 $1,536
 $3,141
Net income—
 128
 128
Common stock dividends—
 (52) (52)
Balance, March 31, 2018$1,605
 $1,612
 $3,217

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions)2018 2017 2018 2017
Operating revenues       
Electric operating revenues$1,052
 $1,032
 $2,202
 $2,100
Natural gas operating revenues28
 22
 106
 87
Revenues from alternative revenue programs(7) 8
 12
 38
Operating revenues from affiliates3
 12
 7
 23
Total operating revenues1,076
 1,074
 2,327
 2,248
Operating expenses       
Purchased power288
 259
 662
 547
Purchased fuel12
 9
 53
 39
Purchased power and fuel from affiliates81
 115
 186
 259
Operating and maintenance218
 231
 489
 454
Operating and maintenance from affiliates37
 38
 74
 70
Depreciation, amortization and accretion180
 165
 363
 332
Taxes other than income107
 110
 221
 221
Total operating expenses923
 927
 2,048
 1,922
Gain on sales of assets—
 1
 —
 1
Operating income153
 148

279
 327
Other income and (deductions)       
Interest expense, net(65) (59) (128) (122)
Other, net11
 13
 22
 26
Total other income and (deductions)(54) (46) (106) (96)
Income before income taxes99
 102
 173
 231
Income taxes15
 36
 24
 26
Net income$84
 $66
 $149
 $205
Comprehensive income$84
 $66
 $149
 $205

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Operating revenues   
Electric operating revenues$1,139
 $1,151
Natural gas operating revenues71
 78
Revenues from alternative revenue programs15
 18
Operating revenues from affiliates3
 4
Total operating revenues1,228
 1,251
Operating expenses   
Purchased power355
 374
Purchased fuel34
 41
Purchased power and fuel from affiliates101
 105
Operating and maintenance239
 271
Operating and maintenance from affiliates33
 38
Depreciation, amortization and accretion180
 183
Taxes other than income111
 113
Total operating expenses1,053
 1,125
Operating income175
 126
Other income and (deductions)   
Interest expense, net(65) (63)
Other, net12
 11
Total other income and (deductions)(53) (52)
Income before income taxes122
 74
Income taxes5
 9
Net income$117
 $65
Comprehensive income$117
 $65

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 Six Months Ended
June 30,
(In millions)2018 2017
Cash flows from operating activities  
Net income$149
 $205
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization363
 332
Gain on sales of long-lived assets—
 (1)
Deferred income taxes and amortization of investment tax credits14
 59
Other non-cash operating activities71
 28
Changes in assets and liabilities:   
Accounts receivable(28) (3)
Receivables from and payables to affiliates, net4
 (7)
Inventories8
 (19)
Accounts payable and accrued expenses66
 (61)
Income taxes13
 87
Pension and non-pension postretirement benefit contributions(62) (68)
Other assets and liabilities(111) (149)
Net cash flows provided by operating activities487
 403
Cash flows from investing activities   
Capital expenditures(629) (671)
Proceeds from sales of long-lived assets—
 1
Other investing activities2
 —
Net cash flows used in investing activities(627)
(670)
Cash flows from financing activities   
Changes in short-term borrowings(228) 45
Proceeds from short-term borrowings with maturities greater than 90 days125
 —
Repayments of short-term borrowings with maturities greater than 90 days—
 (500)
Issuance of long-term debt300
 202
Retirement of long-term debt(25) (120)
Distributions to member(109) (131)
Contributions from member235
 751
Change in Exelon intercompany money pool7
 —
Other financing activities(7) (2)
Net cash flows provided by financing activities298
 245
Increase (Decrease) in cash, cash equivalents and restricted cash158
 (22)
Cash, cash equivalents and restricted cash at beginning of period95
 236
Cash, cash equivalents and restricted cash at end of period$253
 $214

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Cash flows from operating activities  
Net income$117
 $65
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization180
 183
Deferred income taxes and amortization of investment tax credits—
 17
Other non-cash operating activities35
 53
Changes in assets and liabilities:   
Accounts receivable(11) (9)
Receivables from and payables to affiliates, net(8) 10
Inventories(12) 4
Accounts payable and accrued expenses(9) 44
Income taxes4
 (9)
Pension and non-pension postretirement benefit contributions(6) (55)
Other assets and liabilities(61) (24)
Net cash flows provided by operating activities229
 279
Cash flows from investing activities   
Capital expenditures(358) (258)
Other investing activities1
 —
Net cash flows used in investing activities(357)
(258)
Cash flows from financing activities   
Changes in short-term borrowings147
 57
Retirement of long-term debt(5) (12)
Distributions to member(128) (71)
Contributions from member19
 —
Change in Exelon intercompany money pool—
 13
Net cash flows provided by (used in) financing activities33
 (13)
(Decrease) increase in cash, cash equivalents and restricted cash(95) 8
Cash, cash equivalents and restricted cash at beginning of period186
 95
Cash, cash equivalents and restricted cash at end of period$91
 $103

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017
ASSETS   
Current assets   
Cash and cash equivalents$195
 $30
Restricted cash and cash equivalents38
 42
Accounts receivable, net   
Customer495
 486
Other201
 206
Inventories, net   
Gas held in storage5
 7
Materials and supplies145
 151
Regulatory assets512
 554
Other81
 75
Total current assets1,672

1,551
Property, plant and equipment, net12,929
 12,498
Deferred debits and other assets   
Regulatory assets2,439
 2,493
Investments133
 132
Goodwill4,005
 4,005
Long-term note receivable—
 4
Prepaid pension asset513
 490
Deferred income taxes5
 4
Other70
 70
Total deferred debits and other assets7,165

7,198
Total assets(a)
$21,766

$21,247

Table of Contents
(In millions)March 31, 2019 December 31, 2018
ASSETS   
Current assets   
Cash and cash equivalents$33
 $124
Restricted cash and cash equivalents39
 43
Accounts receivable, net   
Customer445
 453
Other189
 177
Receivable from affiliates1
 —
Inventories, net   
Fossil Fuel2
 9
Materials and supplies184
 163
Regulatory assets506
 489
Other54
 75
Total current assets1,453

1,533
Property, plant and equipment, net13,619
 13,446
Deferred debits and other assets   
Regulatory assets2,236
 2,312
Investments132
 130
Goodwill4,005
 4,005
Prepaid pension asset467
 486
Deferred income taxes12
 12
Other370
 60
Total deferred debits and other assets7,222

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

$21,984

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017March 31, 2019 December 31, 2018
LIABILITIES AND MEMBER'S EQUITY      
Current liabilities      
Short-term borrowings$247
 $350
$326
 $179
Long-term debt due within one year379
 396
125
 125
Accounts payable514
 348
441
 496
Accrued expenses220
 261
253
 256
Payables to affiliates94
 90
87
 94
Borrowings from Exelon intercompany money pool7
 —
Regulatory liabilities76
 84
Unamortized energy contract liabilities134
 188
123
 119
Customer deposits111
 119
117
 116
Merger related obligation38
 42
Regulatory liabilities125
 56
Other57
 81
127
 123
Total current liabilities1,926
 1,931
1,675
 1,592
Long-term debt5,737
 5,478
6,119
 6,134
Deferred credits and other liabilities      
Regulatory liabilities1,834
 1,872
Deferred income taxes and unamortized investment tax credits2,146
 2,070
2,182
 2,146
Asset retirement obligations16
 16
52
 52
Non-pension postretirement benefit obligations100
 105
101
 103
Regulatory liabilities1,829
 1,864
Unamortized energy contract liabilities504
 561
416
 442
Other403
 389
630
 369
Total deferred credits and other liabilities5,003
 5,013
5,210
 4,976
Total liabilities(a)
12,666
 12,422
13,004
 12,702
Commitments and contingencies
 

 
Member's equity      
Membership interest9,070
 8,835
9,239
 9,220
Undistributed earnings (losses)30
 (10)
Undistributed earnings51
 62
Total member's equity9,100

8,825
9,290

9,282
Total liabilities and member's equity$21,766

$21,247
$22,294

$21,984
__________
(a)PHI’s consolidated total assets include $37$31 million and $41$33 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $88$64 million and $102$69 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 32 — Variable Interest Entities for additional information.

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTSTATEMENTS OF CHANGES IN EQUITY
(Unaudited)
(In millions)Membership Interest Undistributed Earnings (Losses) Member's Equity
Balance, December 31, 2017$8,835
 $(10) $8,825
Net income—
 149
 149
Distribution to member—
 (109) (109)
Contribution from member235
 —
 235
Balance, June 30, 2018$9,070
 $30
 $9,100
 Three Months Ended March 31, 2019
(In millions)Membership Interest Undistributed Earnings (Losses) Member's Equity
Balance, December 31, 2018$9,220
 $62
 $9,282
Net income—
 117
 117
Distributions to member—
 (128) (128)
Contributions from member19
 —
 19
Balance, March 31, 2019$9,239
 $51
 $9,290

Table of Contents
 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




POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended June 30,
Six Months Ended June 30,
(In millions)2018
2017
2018
2017
Operating revenues       
Electric operating revenues$531
 $508
 $1,067
 $1,022
Revenues from alternative revenue programs(10) 5
 10
 20
Operating revenues from affiliates2
 1
 3
 3
Total operating revenues523
 514
 1,080
 1,045
Operating expenses       
Purchased power94
 74
 224
 157
Purchased power from affiliates46
 69
 98
 152
Operating and maintenance60
 106
 133
 208
Operating and maintenance from affiliates56
 14
 113
 26
Depreciation and amortization92
 78
 188
 160
Taxes other than income90
 90
 183
 180
Total operating expenses438
 431
 939
 883
Gain on sales of assets—
 1
 —
 1
Operating income85
 84
 141
 163
Other income and (deductions)       
Interest expense, net(32) (28) (63) (58)
Other, net8
 7
 16
 15
Total other income and (deductions)(24) (21) (47) (43)
Income before income taxes61
 63
 94
 120
Income taxes7
 20
 9
 19
Net income$54
 $43
 $85
 $101
Comprehensive income$54
 $43
 $85
 $101

Table of Contents
 Three Months Ended March 31,
(In millions)2019
2018
Operating revenues   
Electric operating revenues$559
 $536
Revenues from alternative revenue programs14
 19
Operating revenues from affiliates2
 2
Total operating revenues575
 557
Operating expenses   
Purchased power117
 130
Purchased power from affiliates70
 52
Operating and maintenance64
 73
Operating and maintenance from affiliates54
 57
Depreciation and amortization94
 96
Taxes other than income92
 93
Total operating expenses491
 501
Operating income84
 56
Other income and (deductions)   
Interest expense, net(34) (31)
Other, net7
 8
Total other income and (deductions)(27) (23)
Income before income taxes57
 33
Income taxes2
 2
Net income$55
 $31
Comprehensive income$55
 $31

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
 Six Months Ended
June 30,
(In millions)2018 2017
Cash flows from operating activities   
Net income$85
 $101
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization188
 160
Deferred income taxes and amortization of investment tax credits(8) 35
Gain on sales of long-lived assets—
 (1)
Other non-cash operating activities24
 —
Changes in assets and liabilities:
 
Accounts receivable(31) (33)
Receivables from and payables to affiliates, net(11) (4)
Inventories2
 (10)
Accounts payable and accrued expenses77
 (45)
Income taxes3
 46
Pension and non-pension postretirement benefit contributions(11) (65)
Other assets and liabilities(91) (55)
Net cash flows provided by operating activities227
 129
Cash flows from investing activities   
Capital expenditures(287) (291)
Proceeds from sales of long-lived assets—
 1
Other investing activities2
 (2)
Net cash flows used in investing activities(285) (292)
Cash flows from financing activities   
Changes in short-term borrowings(26) (23)
Issuance of long-term debt100
 202
Retirement of long-term debt(7) (7)
Dividends paid on common stock(50) (58)
Contribution from parent85
 161
Other financing activities(4) (1)
Net cash flows provided by financing activities98
 274
Increase in cash, cash equivalents and restricted cash40
 111
Cash, cash equivalents and restricted cash at beginning of period40
 42
Cash, cash equivalents and restricted cash at end of period$80
 $153

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Cash flows from operating activities   
Net income$55
 $31
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization94
 96
Deferred income taxes and amortization of investment tax credits(2) 4
Other non-cash operating activities3
 10
Changes in assets and liabilities:   
Accounts receivable(19) —
Receivables from and payables to affiliates, net3
 (18)
Inventories(14) (2)
Accounts payable and accrued expenses(2) 36
Income taxes4
 (3)
Pension and non-pension postretirement benefit contributions(4) (7)
Other assets and liabilities(37) (21)
Net cash flows provided by operating activities81
 126
Cash flows from investing activities   
Capital expenditures(144) (127)
Other investing activities1
 —
Net cash flows used in investing activities(143) (127)
Cash flows from financing activities   
Changes in short-term borrowings65
 34
Dividends paid on common stock(24) (25)
Contributions from parent14
 —
Net cash flows provided by financing activities55
 9
(Decrease) increase in cash, cash equivalents and restricted cash(7) 8
Cash, cash equivalents and restricted cash at beginning of period53
 40
Cash, cash equivalents and restricted cash at end of period$46
 $48

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018
December 31, 2017
ASSETS   
Current assets   
Cash and cash equivalents$47
 $5
Restricted cash and cash equivalents33
 35
Accounts receivable, net   
Customer272
 250
Other91
 87
Inventories, net85
 87
Regulatory assets248
 213
Other11
 33
Total current assets787

710
Property, plant and equipment, net6,207
 6,001
Deferred debits and other assets   
Regulatory assets682
 678
Investments105
 102
Prepaid pension asset321
 322
Other21
 19
Total deferred debits and other assets1,129

1,121
Total assets$8,123

$7,832

Table of Contents
(In millions)March 31, 2019
December 31, 2018
ASSETS   
Current assets   
Cash and cash equivalents$11
 $16
Restricted cash and cash equivalents35
 37
Accounts receivable, net   
Customer219
 225
Other102
 81
Receivables from affiliates1
 1
Inventories, net109
 93
Regulatory assets270
 270
Other22
 37
Total current assets769

760
Property, plant and equipment, net6,534
 6,460
Deferred debits and other assets   
Regulatory assets620
 643
Investments106
 105
Prepaid pension asset311
 316
Other80
 15
Total deferred debits and other assets1,117

1,079
Total assets$8,420

$8,299

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Short-term borrowings$—
 $26
Long-term debt due within one year20
 19
Accounts payable245
 139
Accrued expenses137
 137
Payables to affiliates63
 74
Customer deposits51
 54
Regulatory liabilities30
 3
Merger related obligation38
 42
Current portion of DC PLUG obligation30
 28
Other10
 28
Total current liabilities624

550
Long-term debt2,611
 2,521
Deferred credits and other liabilities   
Regulatory liabilities791
 829
Deferred income taxes and unamortized investment tax credits1,101
 1,063
Non-pension postretirement benefit obligations32
 36
Other311
 300
Total deferred credits and other liabilities2,235

2,228
Total liabilities5,470

5,299
Commitments and contingencies
 
Shareholder's equity   
Common stock1,555
 1,470
Retained earnings1,098
 1,063
Total shareholder's equity2,653
 2,533
Total liabilities and shareholder's equity$8,123
 $7,832

Table of Contents
(In millions)March 31, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Short-term borrowings$105
 $40
Long-term debt due within one year15
 15
Accounts payable188
 214
Accrued expenses139
 126
Payables to affiliates65
 62
Customer deposits55
 54
Regulatory liabilities6
 7
Merger related obligation38
 38
Current portion of DC PLUG obligation30
 30
Other17
 42
Total current liabilities658

628
Long-term debt2,705
 2,704
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits1,081
 1,064
Non-pension postretirement benefit obligations26
 29
Regulatory liabilities805
 822
Other360
 312
Total deferred credits and other liabilities2,272

2,227
Total liabilities5,635

5,559
Commitments and contingencies
 
Shareholder's equity   
Common stock1,650
 1,636
Retained earnings1,135
 1,104
Total shareholder's equity2,785
 2,740
Total liabilities and shareholder's equity$8,420
 $8,299

POTOMAC ELECTRIC POWER COMPANY
STATEMENTSTATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2017$1,470
 $1,063
 $2,533
Net income—
 85
 85
Common stock dividends—
 (50) (50)
Contributions from parent85
 —
 85
Balance, June 30, 2018$1,555

$1,098

$2,653

Table of Contents

 Three Months Ended March 31, 2019
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2018$1,636
 $1,104
 $2,740
Net income—
 55
 55
Common stock dividends—
 (24) (24)
Contributions from parent14
 —
 14
Balance, March 31, 2019$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
Common stock dividends—
 (25) (25)
Balance, March 31, 2018$1,470
 $1,069
 $2,539

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended June 30,
Six Months Ended June 30,
(In millions)2018
2017
2018
2017
Operating revenues       
Electric operating revenues$255
 $258
 $558
 $544
Natural gas operating revenues28
 22
 106
 87
Revenues from alternative revenue programs4
 —
 5
 9
Operating revenues from affiliates2
 2
 4
 4
Total operating revenues289

282

673

644
Operating expenses       
Purchased power72
 64
 162
 141
Purchased fuel12
 9
 53
 38
Purchased power from affiliate30
 40
 76
 91
Operating and maintenance36
 66
 94
 133
Operating and maintenance from affiliates41
 8
 81
 15
Depreciation and amortization43
 40
 88
 79
Taxes other than income13
 14
 28
 28
Total operating expenses247

241

582

525
Operating income42

41

91

119
Other income and (deductions)       
Interest expense, net(14) (13) (27) (25)
Other, net3
 3
 5
 6
Total other income and (deductions)(11)
(10)
(22)
(19)
Income before income taxes31
 31
 69
 100
Income taxes5
 12
 12
 24
Net income$26

$19

$57

$76
Comprehensive income$26
 $19
 $57
 $76

Table of Contents
 Three Months Ended March 31,
(In millions)2019
2018
Operating revenues   
Electric operating revenues$307
 $303
Natural gas operating revenues71
 78
Revenues from alternative revenue programs—
 1
Operating revenues from affiliates2
 2
Total operating revenues380

384
Operating expenses   
Purchased power107
 90
Purchased fuel34
 41
Purchased power from affiliate23
 46
Operating and maintenance45
 57
Operating and maintenance from affiliates39
 41
Depreciation and amortization46
 45
Taxes other than income14
 15
Total operating expenses308

335
Operating income72

49
Other income and (deductions)   
Interest expense, net(15) (13)
Other, net3
 2
Total other income and (deductions)(12)
(11)
Income before income taxes60
 38
Income taxes7
 7
Net income$53

$31
Comprehensive income$53
 $31

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
 Six Months Ended
June 30,
(In millions)2018
2017
Cash flows from operating activities   
Net income$57
 $76
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization88
 79
Deferred income taxes and amortization of investment tax credits9
 33
Other non-cash operating activities14
 (3)
Changes in assets and liabilities:   
Accounts receivable18
 12
Receivables from and payables to affiliates, net(22) (2)
Inventories4
 (3)
Accounts payable and accrued expenses10
 18
Income taxes16
 13
Other assets and liabilities22
 (29)
Net cash flows provided by operating activities216

194
Cash flows from investing activities   
Capital expenditures(166) (192)
Other investing activities1
 1
Net cash flows used in investing activities(165)
(191)
Cash flows from financing activities   
Changes in short-term borrowings(216) 25
Issuance of long-term debt200
 —
Retirement of long-term debt(4) (14)
Dividends paid on common stock(40) (54)
Contribution from parent150
 —
Other financing activities(2) —
Net cash flows provided by (used in) financing activities88

(43)
Increase (Decrease) in cash, cash equivalents and restricted cash139
 (40)
Cash, cash equivalents and restricted cash at beginning of period2
 46
Cash, cash equivalents and restricted cash at end of period$141

$6

Table of Contents
 Three Months Ended
March 31,
(In millions)2019
2018
Cash flows from operating activities   
Net income$53
 $31
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization46
 45
Deferred income taxes and amortization of investment tax credits1
 10
Other non-cash operating activities11
 19
Changes in assets and liabilities:   
Accounts receivable(5) (1)
Receivables from and payables to affiliates, net(15) (16)
Inventories1
 7
Accounts payable and accrued expenses11
 18
Income taxes5
 (5)
Other assets and liabilities(10) 7
Net cash flows provided by operating activities98

115
Cash flows from investing activities   
Capital expenditures(78) (65)
Net cash flows used in investing activities(78)
(65)
Cash flows from financing activities   
Changes in short-term borrowings5
 (5)
Retirement of long-term debt—
 (4)
Dividends paid on common stock(41) (36)
Net cash flows used in financing activities(36)
(45)
(Decrease) increase in cash, cash equivalents and restricted cash(16) 5
Cash, cash equivalents and restricted cash at beginning of period24
 2
Cash, cash equivalents and restricted cash at end of period$8

$7

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017
ASSETS   
Current assets   
Cash and cash equivalents$141
 $2
Accounts receivable, net   
Customer119
 146
Other43
 38
Receivables from affiliates1
 —
Inventories, net   
Gas held in storage5
 7
Materials and supplies34
 36
Regulatory assets64
 69
Other18
 27
Total current assets425

325
Property, plant and equipment, net3,689
 3,579
Deferred debits and other assets   
Regulatory assets242
 245
Goodwill8
 8
Prepaid pension asset189
 193
Other9
 7
Total deferred debits and other assets448

453
Total assets$4,562

$4,357

Table of Contents
(In millions)March 31, 2019 December 31, 2018
ASSETS   
Current assets   
Cash and cash equivalents$7
 $23
Restricted cash and cash equivalents1
 1
Accounts receivable, net   
Customer141
 134
Other39
 46
Receivables from affiliates2
 —
Inventories, net   
Fossil Fuel2
 9
Materials and supplies43
 37
Regulatory assets60
 59
Other21
 27
Total current assets316

336
Property, plant and equipment, net3,848
 3,821
Deferred debits and other assets   
Regulatory assets225
 231
Goodwill8
 8
Prepaid pension asset182
 186
Other81
 6
Total deferred debits and other assets496

431
Total assets$4,660

$4,588

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Short-term borrowings$—
 $216
Long-term debt due within one year79
 83
Accounts payable111
 82
Accrued expenses45
 35
Payables to affiliates25
 46
Customer deposits34
 35
Regulatory liabilities67
 42
Other6
 8
Total current liabilities367
 547
Long-term debt1,415
 1,217
Deferred credits and other liabilities   
Regulatory liabilities588
 593
Deferred income taxes and unamortized investment tax credits626
 603
Non-pension postretirement benefit obligations13
 14
Other51
 48
Total deferred credits and other liabilities1,278

1,258
Total liabilities3,060

3,022
Commitments and contingencies
 
Shareholder's equity   
Common stock914
 764
Retained earnings588
 571
Total shareholder's equity1,502

1,335
Total liabilities and shareholder's equity$4,562

$4,357

Table of Contents
(In millions)March 31, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Short-term borrowings$5
 $—
Long-term debt due within one year91
 91
Accounts payable98
 111
Accrued expenses50
 39
Payables to affiliates21
 33
Customer deposits36
 35
Regulatory liabilities49
 59
Other16
 7
Total current liabilities366
 375
Long-term debt1,404
 1,403
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits643
 628
Non-pension postretirement benefits obligations16
 17
Regulatory liabilities596
 606
Other114
 50
Total deferred credits and other liabilities1,369

1,301
Total liabilities3,139

3,079
Commitments and contingencies
 
Shareholder's equity   
Common stock914
 914
Retained earnings607
 595
Total shareholder's equity1,521

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

$4,588

DELMARVA POWER & LIGHT COMPANY
STATEMENTSTATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Three Months Ended March 31, 2019
(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
Balance, December 31, 2018$914
 $595
 $1,509
Net income—
 57
 57
—
 53
 53
Common stock dividends—
 (40) (40)—
 (41) (41)
Contribution from parent150
 —
 150
Balance, June 30, 2018$914
 $588
 $1,502
Balance, March 31, 2019$914
 $607
 $1,521

Table of Contents
 Three Months Ended March 31, 2018
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2017$764
 $571
 $1,335
Net income—
 31
 31
Common stock dividends—
 (36) (36)
Balance, March 31, 2018$764
 $566
 $1,330


ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended June 30, Six Months Ended
June 30,
(In millions)2018 2017 2018 2017
Operating revenues       
Electric operating revenues$265
 $266
 $576
 $534
Revenues from alternative revenue programs(1) 3
 (3) 9
Operating revenues from affiliates1
 1
 2
 1
Total operating revenues265
 270
 575
 544
Operating expenses       
Purchased power122
 121
 277
 250
Purchased power from affiliates6
 7
 12
 16
Operating and maintenance40
 71
 95
 139
Operating and maintenance from affiliates35
 7
 70
 13
Depreciation and amortization36
 37
 69
 72
Taxes other than income1
 2
 3
 4
Total operating expenses240
 245
 526
 494
Operating income25

25
 49

50
Other income and (deductions)       
Interest expense, net(16) (15) (32) (30)
Other, net1
 2
 1
 4
Total other income and (deductions)(15) (13) (31) (26)
Income before income taxes10
 12
 18
 24
Income taxes2
 4
 3
 (12)
Net income$8

$8

$15

$36
Comprehensive income$8
 $8
 $15
 $36

Table of Contents
 Three Months Ended
March 31,
(In millions)2019 2018
Operating revenues   
Electric operating revenues$271
 $311
Revenues from alternative revenue programs1
 (2)
Operating revenues from affiliates1
 1
Total operating revenues273
 310
Operating expenses   
Purchased power131
 155
Purchased power from affiliates8
 6
Operating and maintenance47
 54
Operating and maintenance from affiliates34
 36
Depreciation and amortization31
 33
Taxes other than income1
 3
Total operating expenses252
 287
Operating income21

23
Other income and (deductions)   
Interest expense, net(14) (16)
Other, net3
 1
Total other income and (deductions)(11) (15)
Income before income taxes10
 8
Income taxes—
 1
Net income$10

$7
Comprehensive income$10
 $7

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 Six Months Ended
June 30,
(In millions)2018
2017
Cash flows from operating activities   
Net income$15
 $36
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization69
 72
Deferred income taxes and amortization of investment tax credits6
 (8)
Other non-cash operating activities12
 7
Changes in assets and liabilities:   
Accounts receivable(13) 18
Receivables from and payables to affiliates, net(4) (6)
Inventories4
 (3)
Accounts payable and accrued expenses14
 3
Income taxes3
 11
Pension and non-pension postretirement benefit contributions(6) —
Other assets and liabilities(33) (53)
Net cash flows provided by operating activities67
 77
Cash flows from investing activities   
Capital expenditures(170) (175)
Other investing activities(2) —
Net cash flows used in investing activities(172) (175)
Cash flows from financing activities   
Changes in short-term borrowings14
 42
Proceeds from short-term borrowings with maturities greater than 90 days125
 —
Retirement of long-term debt(15) (17)
Dividends paid on common stock(19) (22)
Other financing activities—
 (1)
Net cash flows provided by financing activities105
 2
Increase (Decrease) in cash, cash equivalents and restricted cash—
 (96)
Cash, cash equivalents and restricted cash at beginning of period31
 133
Cash, cash equivalents and restricted cash at end of period$31

$37

Table of Contents
 Three Months Ended
March 31,
(In millions)2019
2018
Cash flows from operating activities   
Net income$10
 $7
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization31
 33
Deferred income taxes and amortization of investment tax credits—
 2
Other non-cash operating activities5
 9
Changes in assets and liabilities:   
Accounts receivable13
 (5)
Receivables from and payables to affiliates, net(4) (4)
Inventories1
 —
Accounts payable and accrued expenses12
 30
Income taxes(1) —
Pension and non-pension postretirement benefit contributions—
 (6)
Other assets and liabilities(7) (7)
Net cash flows provided by operating activities60
 59
Cash flows from investing activities   
Capital expenditures(128) (63)
Other investing activities—
 (1)
Net cash flows used in investing activities(128) (64)
Cash flows from financing activities   
Changes in short-term borrowings77
 28
Retirement of long-term debt(4) (8)
Dividends paid on common stock(12) (9)
Contributions from parent5
 —
Net cash flows provided by financing activities66
 11
(Decrease) increase in cash, cash equivalents and restricted cash(2) 6
Cash, cash equivalents and restricted cash at beginning of period30
 31
Cash, cash equivalents and restricted cash at end of period$28

$37

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2018 December 31, 2017
ASSETS   
Current assets   
Cash and cash equivalents$6
 $2
Restricted cash and cash equivalents5
 6
Accounts receivable, net   
Customer103
 92
Other50
 56
Inventories, net25
 29
Prepaid utility taxes36
 —
Regulatory assets60
 71
Other7
 2
Total current assets292
 258
Property, plant and equipment, net2,831
 2,706
Deferred debits and other assets   
Regulatory assets381
 359
Long-term note receivable—
 4
Prepaid pension asset73
 73
Other42
 45
Total deferred debits and other assets496
 481
Total assets(a)
$3,619
 $3,445

Table of Contents
(In millions)March 31, 2019 December 31, 2018
ASSETS   
Current assets   
Cash and cash equivalents$6
 $7
Restricted cash and cash equivalents3
 4
Accounts receivable, net   
Customer85
 95
Other52
 55
Receivables from affiliates1
 1
Inventories, net32
 33
Regulatory assets53
 40
Other6
 5
Total current assets238
 240
Property, plant and equipment, net3,041
 2,966
Deferred debits and other assets   
Regulatory assets377
 386
Prepaid pension asset63
 67
Other64
 40
Total deferred debits and other assets504
 493
Total assets(a)
$3,783
 $3,699

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

(In millions)June 30, 2018 December 31, 2017March 31, 2019 December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY      
Current liabilities      
Short-term borrowings$247
 $108
$216
 $139
Long-term debt due within one year275
 281
19
 18
Accounts payable143
 118
139
 154
Accrued expenses35
 33
38
 35
Payables to affiliates25
 29
24
 28
Customer deposits26
 31
26
 26
Regulatory liabilities29
 11
20
 18
Other9
 8
10
 4
Total current liabilities789
 619
492
 422
Long-term debt832
 840
1,165
 1,170
Deferred credits and other liabilities      
Deferred income taxes and unamortized investment tax credits501
 493
539
 535
Non-pension postretirement benefit obligations14
 14
17
 17
Regulatory liabilities418
 411
395
 402
Other26
 25
46
 27
Total deferred credits and other liabilities959
 943
997
 981
Total liabilities(a)
2,580
 2,402
2,654
 2,573
Commitments and contingencies
 

 
Shareholder's equity      
Common stock912
 912
984
 979
Retained earnings127
 131
145
 147
Total shareholder's equity1,039

1,043
1,129

1,126
Total liabilities and shareholder's equity$3,619

$3,445
$3,783

$3,699
__________
(a)ACE’s consolidated total assets include $25$22 million and $29$23 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $76$54 million and $90$59 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 32 — Variable Interest Entities for additional information.

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTSTATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Three Months Ended March 31, 2019
(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
Balance, December 31, 2018$979
 $147
 $1,126
Net income—
 15
 15
—
 10
 10
Common stock dividends—
 (19) (19)—
 (12) (12)
Balance, June 30, 2018$912

$127
 $1,039
Contributions from parent

5
 —
 5
Balance, March 31, 2019$984

$145
 $1,129

 Three Months Ended March 31, 2018
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2017$912
 $131
 $1,043
Net income—
 7
 7
Common stock dividends—
 (9) (9)
Balance, March 31, 2018$912
 $129
 $1,041


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


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
Registrant1234567891011121314151617181920123456789101112131415161718
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 through its principal subsidiaries in the generation, delivery and marketing of energy generationthrough Generation and the energy distribution and transmission businesses.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. SixFive reportable segments: Mid-Atlantic, Midwest, New England, 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 June 30,March 31, 2019 and 2018 and 2017 and for the three and six 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, 2017 revised2018 Consolidated Balance Sheets were derived from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2018.2019. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.

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

Prior Period Adjustmentsnormally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and Reclassificationsregulations.
New Accounting Standards (All Registrants)
CertainNew 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) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases,
an implementation expedient which allows the requirements of the standard in the period of adoption with no restatement of prior year amountsperiods, 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 Consolidated Balance Sheets and Consolidated Statements of Changes in Shareholders' Equity have been recasted to reflect new accounting standards issued byEquity. The most significant impact was the FASB and adopted as of January 1, 2018.
Beginning on January 1, 2018, Exelon adopted the following new accounting standards requiring reclassification or adjustments to previously reported information as follows:
Statement of Cash Flows: Classification of Restricted Cash. The Registrants applied the new guidance using the full retrospective method and, accordingly, have recasted the presentation of restricted cash in their Consolidated Statements of Cash Flows in the prior periods presented. See Note 18 — Supplemental Financial Information for additional information.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.  Exelon early adopted and retrospectively applied the new guidance to when the effectsrecognition of the TCJA wereROU assets and lease liabilities for operating leases. The operating ROU assets and lease liabilities recognized and, accordingly, recasted its December 31, 2017 AOCI and retained earningsupon adoption are materially consistent with the balances presented in its Consolidated Balance Sheet and Consolidated Statement of Changes in Shareholders' Equity.  Exelon's accounting policy is to release the stranded tax effects from AOCI related to its pension and OPEB plans under a portfolio (or aggregate) approach as an entire pension or OPEB plan is liquidated or terminated. See Note 2 — New Accounting Standards for additional information.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. Exelon applied this guidance retrospectively for the presentation of the service and other non-service costs components of net benefit cost and, accordingly, have recasted those amounts, which were not material, in its Consolidated Statement of Operations and Comprehensive Income in prior periods presented. As part of the adoption, Exelon elected the practical expedient that permits an employer to use the amounts disclosed in its pension and other postretirement benefit plan note for the comparative periods as the estimation basis for applying the retrospective presentation requirements. See Note 14 — Retirement Benefits for additional information.
Revenue from Contracts with Customers. The Registrants applied the new guidance using the full retrospective method and, accordingly, have recasted certain amounts in their Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows, Consolidated Balance Sheets, Consolidated Statements of Changes in Shareholders' Equity and Combined Notes to the Consolidated Financial Statements in the prior periods presented. The amounts recasted in the Registrants' Consolidated Statements of Operations and Comprehensive Income are shown in the table below. The amounts recasted in the Registrants’ Consolidated Statements of Cash Flows, Consolidated Balance Sheets, Consolidated Statements of Changes in Shareholders' Equity and Combined Notes to Consolidated Financial Statements were not material.Statements. See Note 5 — Revenue from Contracts with Customers- Leases for additional information.

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

Three Months Ended June 30, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating Revenues - As reported                 
Competitive business revenues$3,908
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Rate-regulated utility revenues3,715
 —
 —
 —
 —
 —
 —
 —
 —
Operating revenues—
 3,906
 —
 —
 —
 —
 —
 —
 —
Electric operating revenues—
 —
 1,354
 548
 569
 1,040
 513
 258
 269
Natural gas operating revenues—
 —
 —
 80
 102
 22
 —
 22
 —
Operating revenues from affiliates—
 268
 3
 2
 3
 12
 1
 2
 1
Total operating revenues$7,623
 $4,174
 $1,357
 $630
 $674
 $1,074
 $514
 $282
 $270
                  
Operating Revenues - Adjustments                 
Competitive business revenues$42
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Rate-regulated utility revenues(58) —
 —
 —
 —
 —
 —
 —
 —
Operating revenues—
 42
 —
 —
 —
 —
 —
 —
 —
Electric operating revenues—
 —
 (18) —
 (24) (8) (5) —
 (3)
Natural gas operating revenues—
 —
 —
 —
 (8) —
 —
 —
 —
Revenues from alternative revenue programs58
 —
 18
 —
 32
 8
 5
 —
 3
Operating revenues from affiliates—
 —
 —
 —
 —
 —
 —
 —
 —
Total operating revenues$42
 $42
 $—
 $—
 $—
 $—
 $—
 $—
 $—
                  
Operating Revenues - Retrospective application                 
Competitive business revenues$3,950
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Rate-regulated utility revenues3,657
 —
 —
 —
 —
 —
 —
 —
 —
Operating revenues—
 3,948
 —
 —
 —
 —
 —
 —
 —
Electric operating revenues—
 —
 1,336
 548
 545
 1,032
 508
 258
 266
Natural gas operating revenues—
 —
 —
 80
 94
 22
 —
 22
 —
Revenues from alternative revenue programs58
 —
 18
 —
 32
 8
 5
 —
 3
Operating revenues from affiliates—
 268
 3
 2
 3
 12
 1
 2
 1
Total operating revenues$7,665
 $4,216
 $1,357
 $630
 $674
 $1,074
 $514
 $282
 $270

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

Six Months Ended June 30, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating Revenues - As reported                 
Competitive business revenues$8,468
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Rate-regulated utility revenues7,913
 —
 —
 —
 —
 —
 —
 —
 —
Operating revenues—
 8,463
 —
 —
 —
 —
 —
 —
 —
Electric operating revenues—
 —
 2,647
 1,138
 1,234
 2,138
 1,042
 553
 543
Natural gas operating revenues—
 —
 —
 285
 383
 87
 —
 87
 —
Operating revenues from affiliates—
 598
 9
 3
 8
 23
 3
 4
 1
Total operating revenues$16,381
 $9,061
 $2,656
 $1,426
 $1,625
 $2,248
 $1,045
 $644
 $544
                  
Operating Revenues - Adjustments                 
Competitive business revenues$32
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Rate-regulated utility revenues(137) —
 —
 —
 —
 —
 —
 —
 —
Operating revenues—
 32
 —
 —
 —
 —
 —
 —
 —
Electric operating revenues—
 —
 (32) —
 (48) (38) (20) (9) (9)
Natural gas operating revenues—
 —
 —
 —
 (18) —
 —
 —
 —
Revenues from alternative revenue programs137
 —
 32
 —
 66
 38
 20
 9
 9
Operating revenues from affiliates—
 —
 —
 —
 —
 —
 —
 —
 —
Total operating revenues$32
 $32
 $—
 $—
 $—
 $—
 $—
 $—
 $—
                  
Operating Revenues - Retrospective application                 
Competitive business revenues$8,500
 $—
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Rate-regulated utility revenues7,776
 —
 —
 —
 —
 —
 —
 —
 —
Operating revenues—
 8,495
 —
 —
 —
 —
 —
 —
 —
Electric operating revenues—
 —
 2,615
 1,138
 1,186
 2,100
 1,022
 544
 534
Natural gas operating revenues—
 —
 —
 285
 365
 87
 —
 87
 —
Revenues from alternative revenue programs137
 —
 32
 —
 66
 38
 20
 9
 9
Operating revenues from affiliates—
 598
 9
 3
 8
 23
 3
 4
 1
Total operating revenues$16,413
 $9,093
 $2,656
 $1,426
 $1,625
 $2,248
 $1,045
 $644
 $544

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

Revenues (All Registrants)
Operating Revenues. The Registrants’ operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services, utility revenues from alternative revenue programs (ARP), and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and natural gas tariff sales, distribution and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. See Note 5 — Revenue from Contracts with Customers and Note 6 —Regulatory Matters for additional information.
RTOs and ISOs. In RTO and ISO markets that facilitate the dispatch of energy and energy-related products, the Registrants generally report sales and purchases conducted on a net hourly basis in either revenues or purchased power on their Consolidated Statements of Operations and Comprehensive Income, the classification of which depends on the net hourly sale or purchase position. In addition, capacity revenue and expense classification is based on the net sale or purchase position of the Registrants in the different RTOs and ISOs.
Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. For example, gas transactions may be used to hedge the sale of power. This will result in the change in fair value recorded through revenue. To the extent a Utility Registrant receives full cost recovery for energy procurement and related costs from retail customers, it records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets. See Note 6 — Regulatory Matters and Note 10 — Derivative Financial Instruments for additional information.
Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees that are levied by state or local governments on the sale or distribution of natural gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed directly on the Registrants. The Registrants do not recognize revenue or expense in their Consolidated Statements of Operations and Comprehensive Income when these taxes are imposed on the customer, such as sales taxes. However, when these taxes are imposed directly on the Registrants, such as gross receipts taxes or other surcharges or fees, the Registrants recognize revenue for the taxes collected from customers along with an offsetting expense. See Note 18 — Supplemental Financial Information for Generation’s, ComEd’s, PECO’s, BGE’s, Pepco’s, DPL’s and ACE’s utility taxes that are presented on a gross basis.

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

2.    New Accounting Standards (All Registrants)
New Accounting Standards Adopted: In 2018, the Registrants have adopted the following new authoritative accounting guidance issued by the FASB.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Issued February 2018): Provides an election for a reclassification from AOCI to Retained earnings to eliminate the stranded tax effects resulting from the TCJA. This standard is effective January 1, 2019, with early adoption permitted, and may be applied either in the period of adoption or retrospective to each period in which the effects of the TCJA were recognized. Exelon early adopted this standard during the first quarter 2018 and elected to apply the guidance retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million related to deferred income taxes associated with Exelon’s pension and OPEB obligations. There was no impact for Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE.
See Note 1 — Significant Accounting Policies of the Exelon 20172018 Form 10-K for additional information on other new accounting standards issued and adopted as of January 1, 2018.2019.
New Accounting Standards Issued and Not Yet Adopted as of June 30, 2018: March 31, 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 June 30, 2018.March 31, 2019. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) onin their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation that such standards will not significantly impact the Registrants' financial reporting.
LeasesGoodwill Impairment (Issued February 2016):January 2017). Increases transparencySimplifies 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 comparability among organizations by recognizing lease assets and lease liabilities onDPL have goodwill as of March 31, 2019. This updated guidance is not currently expected to impact the balance sheet and disclosing key information about leasing arrangements.Registrants’ financial reporting. The standard is effective January 1, 2019. Early2020, with early adoption is permitted; however, the Registrants will not early adopt the standard. The issued guidance required a modified retrospective transition approach, which requires lesseespermitted, and lessors to recognize and measure leases at the beginning of the earliest period presented (January 1, 2017). In July 2018, the FASB issued an amendment to the standard giving entities the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods.  Exelon plans to elect this expedient.
The new guidance requires lessees to recognize both the right-of-use assets and lease liabilities in the balance sheet for most leases, whereas today only finance lease liabilities (referred to as capital leases) are recognized in the balance sheet. In addition, the definition of a lease has been revised which may result in changes to the classification of an arrangement as a lease. Under the new guidance, an arrangement that conveys the right to control the use of an identified asset by obtaining substantially all of its economic benefits and directing how it is used is a lease, whereas the current definition focuses on the ability to control the use of the asset or to obtain its output. Quantitative and qualitative disclosures related to the amount, timing and judgments of an entity’s accounting for leases and the related cash flows are expanded. Disclosure requirements apply to both lessees and lessors, whereas current disclosures relate only to lessees. Significant changes to lease systems, processes and procedures are required to implement the requirements of the new standard. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from current GAAP. Lessor accounting is also largely unchanged.
The standard provides a number of transition practical expedients that entities may elect. These include a "package of three" expedients that must be taken together and allow entities to (1) not reassess

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

whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. The Registrants expect to elect this practical expedient.
In January 2018, the FASB issued additional guidance which provides another optional transition practical expedient. This practical expedient allows entities to not evaluate land easements under the new guidance at adoption if they were not previously accounted for as leases.
The Registrants have assessed the lease standard and are executingapplied on a detailed implementation plan in preparation for adoption on January 1, 2019. Key activities in the implementation plan include:
Developing a complete lease inventory and abstracting the required data attributes into a lease accounting system that supports the Registrants' lease portfolios and integrates with existing systems.
Evaluating the transition practical expedients available under the guidance.
Identifying, assessing and documenting technical accounting issues, policy considerations and financial reporting implications.
Identifying and implementing changes to processes and controls to ensure all impacts of the new guidance are effectively addressed.prospective basis.
Impairment of Financial Instruments (Issued June 2016):.Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects the entity’s current estimate of credit losses expected to be incurred over the life of the financial instrument. The standard does not make changes to the existing impairment models for non-financial assets such as fixed assets, intangibles and goodwill. The standard will be effective January 1, 2020 (with early adoption as of January 1, 2019 permitted) and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption.
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 June 30, 2018. This updated guidance is not currently expected to impact the Registrants’ financial reporting. The standard is effective January 1, 2020, with early adoption permitted, and must be applied on a prospective basis.
Derivatives and Hedging (Issued September 2017): Allows more financial and nonfinancial hedging strategies to be eligible for hedge accounting. The amendments are intended to more closely align hedge accounting with companies’ risk management strategies, simplify the application of hedge accounting, and increase transparency as to the scope and results of hedging programs. There are also amendments related to effectiveness testing and disclosure requirements. The guidance is effective January 1, 2019 and early adoption is permitted with a modified retrospective transition approach. The Registrants are currently assessing this standard but do not currently expect a significant impact given the limited activity for which the Registrants elect hedge accounting and because the Registrants do not anticipate increasing their use of hedge accounting as a resultimpacts of this standard.

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

3.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)
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 June 30, 2018March 31, 2019 and December 31, 2017,2018, Exelon, Generation, PHI and ACE collectively consolidated five VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated Variable Interest Entities below). As of June 30, 2018March 31, 2019 and December 31, 2017,2018, Exelon and Generation collectively had significant interests in seven other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated Variable Interest Entities below).

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

Consolidated Variable Interest Entities
As of June 30, 2018March 31, 2019 and December 31, 2017,2018, Exelon's and Generation's consolidated VIEs consist of:
energy related companies involved in distributed generation, backup generation and energy development
renewable energy project companies formed by Generation to build, own and operate renewable power facilities
certain retail power and gas companies for which Generation is the sole supplier of energy, and
CENG.
As of June 30, 2018March 31, 2019 and December 31, 2017,2018, Exelon's, PHI's and ACE's consolidated VIE consist of:
ATF, a special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds.
As of June 30, 2018March 31, 2019 and December 31, 2017,2018, ComEd, PECO, BGE, Pepco and DPL did not have any material consolidated VIEs.
As of June 30, 2018March 31, 2019 and December 31, 2017,2018, Exelon and Generation provided the following support to their respective consolidated VIEs:
Generation provides operating and capital funding to the renewable energy project companies and there is limited recourse to Generation related to certain renewable energy project companies.
Generation provides operating and capital funding to one of the energy related companies involved in backup generation.
Generation provides approximately $34$32 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy.

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

Exelon and Generation, where indicated, provide the following support to CENG (see Note 26 — Related Party Transactions of the Exelon 2017 Form 10-K for additional information regarding Generation's and Exelon’s transactions with CENG):CENG:
under power purchase agreementsPPAs with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG nuclear plants not subject to other contractual agreements from January 2015 through the end of the operating life of each respective plant. However, pursuant to amendments dated March 31, 2015, the energy obligations under the Ginna Nuclear Power Plant (Ginna) PPAs were suspended during the term of the Reliability Support Services Agreement (RSSA),RSSA, through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017,
Generation provided a $400 million loan to CENG. As of June 30, 2018, the remaining obligation is $191 million,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 1716 — Commitments and Contingencies for additional information),
Generation and EDF share in the $637$688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and
Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.
As of June 30, 2018March 31, 2019 and December 31, 2017,2018, Exelon, PHI and ACE provided the following support to their respective consolidated VIE:
In the case of ATF, proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the

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

NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three and six months ended June 30, 2018,March 31, 2019, ACE transferred $6 million and $14$4 million to ATF, respectively.ATF. During the three and six months ended June 30, 2017,March 31, 2018, ACE transferred $8 million and $27 million to ATF, respectively.ATF.
For each of the consolidated VIEs, except as otherwise noted:
the assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;
Exelon, Generation, PHI and ACE did not provide any additional material financial support to the VIEs;
Exelon, Generation, PHI and ACE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and

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

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 June 30, 2018March 31, 2019 and December 31, 20172018 are as follows:
June 30, 2018 December 31, 2017March 31, 2019 December 31, 2018
Exelon(a)
 Generation 
PHI(a)
 ACE 
Exelon(a)
 Generation 
PHI(a)
 ACE
Exelon(a)
 Generation 
PHI(a)
 ACE 
Exelon(a)
 Generation 
PHI(a)
 ACE
Current assets$744
 $735
 $9
 $5
 $662
 $652
 $10
 $6
$645
 $639
 $6
 $3
 $938
 $931
 $7
 $4
Noncurrent assets9,234
 9,206
 28
 20
 9,317
 9,286
 31
 23
9,235
 9,210
 25
 19
 9,071
 9,045
 26
 19
Total assets$9,978

$9,941

$37
 $25

$9,979

$9,938

$41
 $29
$9,880

$9,849

$31
 $22

$10,009

$9,976

$33
 $23
Current liabilities$268
 $238
 $30
 $26
 $308
 $272
 $36
 $32
$748
 $725
 $23
 $19
 $274
 $252
 $22
 $19
Noncurrent liabilities3,284
 3,226
 58
 50
 3,316
 3,250
 66
 58
2,831
 2,790
 41
 35
 3,280
 3,233
 47
 40
Total liabilities$3,552

$3,464

$88
 $76

$3,624

$3,522

$102
 $90
$3,579

$3,515

$64
 $54

$3,554

$3,485

$69
 $59
_________
(a)Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.

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

Assets and Liabilities of Consolidated VIEs
Included within the balances above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors or beneficiaries do not have recourse to the general credit of the Registrants. As of June 30, 2018March 31, 2019 and December 31, 2017,2018, these assets and liabilities primarily consisted of the following:
June 30, 2018 December 31, 2017March 31, 2019 December 31, 2018
Exelon (a)

Generation 
PHI (a)
 ACE 
Exelon(a)
 Generation 
PHI (a)
 ACE
Exelon(a)

Generation
PHI(a)
 ACE 
Exelon(a)
 Generation 
PHI(a)
 ACE
Cash and cash equivalents$205
 $205
 $—
 $—
 $126
 $126
 $—
 $—
$125
 $125
 $—
 $—
 $414
 $414
 $—
 $—
Restricted cash77
 72
 5
 5
 64
 58
 6
 6
Restricted cash and cash equivalents58
 55
 3
 3
 66
 62
 4
 4
Accounts receivable, net    
       
                 
Customer149
 149
 —
 —
 170
 170
 —
 —
152
 152
 —
 —
 146
 146
 —
 —
Other32
 32
 —
 —
 25
 25
 —
 —
23
 23
 —
 —
 23
 23
 —
 —
Inventory, net    
       
                 
Materials and supplies208
 208
 —
 —
 205
 205
 —
 —
213
 213
 —
 —
 212
 212
 —
 —
Other current assets47
 43
 4
 —
 45
 41
 4
 —
51
 48
 3
 —
 52
 49
 3
 —
Total current assets718

709

9
 5
 635

625

10
 6
622

616

6
 3
 913

906

7
 4
Property, plant and equipment, net6,157
 6,157
 —
 —
 6,186
 6,186
 —
 —
6,147
 6,147
 —
 —
 6,145
 6,145
 —
 —
Nuclear decommissioning trust funds2,483
 2,483
 —
 —
 2,502
 2,502
 —
 —
NDT funds2,520
 2,520
 —
 —
 2,351
 2,351
 —
 —
Other noncurrent assets254
 226
 28
 20
 274
 243
 31
 23
257
 232
 25
 19
 258
 232
 26
 19
Total noncurrent assets8,894

8,866

28
 20
 8,962

8,931

31
 23
8,924

8,899

25
 19
 8,754

8,728

26
 19
Total assets$9,612

$9,575

$37
 $25
 $9,597

$9,556

$41
 $29
$9,546

$9,515

$31
 $22
 $9,667

$9,634

$33
 $23
Long-term debt due within one year$95
 $66
 $29
 $25
 $102
 $67
 $35
 $31
$567
 $545
 $22
 $19
 $87
 $66
 $21
 $18
Accounts payable74
 74
 —
 —
 114
 114
 —
 —
120
 120
 —
 —
 96
 96
 —
 —
Accrued expenses81
 80
 1
 1
 67
 66
 1
 1
42
 41
 1
 —
 72
 72
 1
 1
Unamortized energy contract liabilities16
 16
 —
 —
 18
 18
 —
 —
13
 13
 —
 —
 15
 15
 —
 —
Other current liabilities2
 2
 —
 —
 7
 7
 —
 —
6
 6
 —
 —
 3
 3
 —
 —
Total current liabilities268
 238
 30
 26
 308
 272
 36
 32
748
 725
 23
 19
 273
 252
 22
 19
Long-term debt1,119
 1,061
 58
 50
 1,154
 1,088
 66
 58
565
 524
 41
 35
 1,072
 1,025
 47
 40
Asset retirement obligations2,088
 2,088
 —
 —
 2,035
 2,035
 —
 —
2,190
 2,190
 —
 —
 2,160
 2,160
 —
 —
Unamortized energy contract liabilities—
 —
 —
 —
 1
 1
 —
 —
Other noncurrent liabilities69
 69
 —
 —
 121
 121
 —
 —
69
 69
 —
 —
 42
 42
 —
 —
Total noncurrent liabilities3,276
 3,218
 58
 50
 3,310
 3,244
 66
 58
2,824
 2,783
 41
 35
 3,275
 3,228
 47
 40
Total liabilities$3,544
 $3,456
 $88
 $76
 $3,618
 $3,516
 $102
 $90
$3,572
 $3,508
 $64
 $54
 $3,548
 $3,480
 $69
 $59
_________
(a)Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
Unconsolidated Variable Interest Entities
Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected onin Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial

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

(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

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

material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.
As of June 30, 2018March 31, 2019 and December 31, 2017,2018, Exelon's and Generation's unconsolidated VIEs consist of:
Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required.
Asset sale agreement with ZionSolutions, LLC and EnergySolutions, Inc. in which Generation has a variable interest but has concluded that consolidation is not required.
Equity investments in distributed energy companies for which Generation has concluded that consolidation is not required.
As of June 30, 2018March 31, 2019 and December 31, 2017, ComEd, PECO, BGE, PHI, Pepco, ACE and DPL2018, the Utility Registrants did not have any material unconsolidated VIEs.
As of June 30, 2018March 31, 2019 and December 31, 2017,2018, Exelon and Generation had significant unconsolidated variable interests in seven VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity investments and certain commercial agreements. Exelon and Generation only include unconsolidated VIEs that are individually material in the tables below. However, Exelon and Generation hashave several individually immaterial VIEs that in aggregate represent a total investment of $9 million.$16 million and $12 million, respectively, as of March 31, 2019. These immaterial VIEs are equity and debt securities in energy development companies. TheAs of March 31, 2019, the maximum exposure to loss related to these securities is limited to the $9 million included in Investments onin Exelon’s and Generation’s Consolidated Balance Sheets.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 present summary information about Exelon's and Generation’s significant unconsolidated VIE entities:  
June 30, 2018
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
March 31, 2019
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
Total assets(a)
$620
 $491
 $1,111
$601
 $463
 $1,064
Total liabilities(a)
37
 224
 261
42
 223
 265
Exelon's ownership interest in VIE(a)
—
 238
 238
—
 214
 214
Other ownership interests in VIE(a)
583
 29
 612
559
 26
 585
Registrants’ maximum exposure to loss:    
    
Carrying amount of equity method investments—
 238
 238
—
 214
 214
Contract intangible asset8
 —
 8
7
 —
 7
Net assets pledged for Zion Station decommissioning(b)
1
 —
 1
December 31, 2017
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
December 31, 2018
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
Total assets(a)
$625
 $509
 $1,134
$597
 $472
 $1,069
Total liabilities(a)
37
 228
 265
37
 222
 259
Exelon's ownership interest in VIE(a)
—
 251
 251
—
 223
 223
Other ownership interests in VIE(a)
588
 30
 618
560
 27
 587
Registrants’ maximum exposure to loss:    
    
Carrying amount of equity method investments—
 251
 251
—
 223
 223
Contract intangible asset8
 —
 8
7
 —
 7
Net assets pledged for Zion Station decommissioning(b)
2
 —
 2
_________
(a)These items represent amounts onin the unconsolidated VIE balance sheets, not onin Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
(b)These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $21 million and $39 million as of June 30, 2018 and December 31, 2017, respectively; offset by payables to ZionSolutions, LLC of $20 million and $37 million as of June 30, 2018 and December 31, 2017, respectively. These items are included to provide information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE. See Note 13 — Nuclear Decommissioning for additional information.
For each of the unconsolidated VIEs, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.
4.3. Mergers, Acquisitions and Dispositions (Exelon and Generation)
AcquisitionDisposition of Handley Generating StationOyster Creek
On November 7, 2017, EGTPJuly 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and all of its indirect wholly owned subsidiaries filed voluntary petitionssubsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for relief under Chapter 11the sale and decommissioning of Title 11Oyster Creek located in Forked River, New Jersey. On September 17, 2018, Oyster Creek permanently ceased generation operations.
Under the terms of the United States Codetransaction, Generation will transfer to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. In addition to the assumption of liability for the full decommissioning and ongoing management of spent fuel, other consideration to be received in the United States Bankruptcy Courttransaction 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 Districtobligations of Delaware, which resulted in ExelonOCEP 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 deconsolidating EGTP's assets and liabilities from their consolidated financial statements inupon the fourth quarteroccurrence of 2017. Concurrently with thespecified events.

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

Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP's generating plants, the Handley Generating Station, subject toAs a potential adjustment for fuel oil and assumption of certain liabilities. In the Chapter 11 Filings, EGTP requested that the proposed acquisitionresult of the Handley Generating Station be consummated through a court-approved and supervised sales process. The acquisition was approved by the Bankruptcy Court in January 2018 and closed on April 4, 2018 for a purchase price of $62 million. The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders.
Acquisition of James A. FitzPatrick Nuclear Generating Station
On March 31, 2017, Generation acquired the 842 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy) for a total purchase price of $289 million, which consisted of a cash purchase price of $110 million and a net cost reimbursement to and on behalf of Entergy of $179 million. As part of the acquisition agreements, Generation provided nuclear fuel and reimbursed Entergy for incremental costs to prepare for and conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the plant for the period after the refueling outage through the acquisition closing date. These reimbursements covered costs that Entergy otherwise would have avoided had it shut down the plant as originally intended in January 2017. The amounts reimbursed by Generation were offset by FitzPatrick's electricity and capacity sales revenues for this same post-outage period. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumed the obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034.
The fair values of FitzPatrick’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices. The valuations performed in the first quarter of 2017 to determine the fair value of the FitzPatrick assets acquired and liabilities assumed were updated in the third quarter of 2017. The purchase price allocation is now final.
For the three months ended2018, 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, 2017, an after-tax bargain purchase gain2019 and $897 million and $777 million of $226 million is included within Exelon'sAssets and Generation's Consolidated Statements of Operations and Comprehensive Income and primarily reflects differences in strategies between Generation and EntergyLiabilities held for the intended use and ultimate decommissioningsale, respectively, at December 31, 2018. Upon remeasurement of the plant. DuringOyster Creek ARO in the third quarter of 2017,2018, Exelon and Generation recordedrecognized an additional after-tax bargain purchase gain of $7$84 million for the three months ended September 30, 2017. The total after tax bargain purchase gain recorded at Exelon and Generation was $233 million for the twelve months ended December 31, 2017. See Note 13 — Nuclear Decommissioning and Note 14 — Retirement Benefits for additional information regarding the FitzPatrick decommissioning ARO and pension and OPEB updates.

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

The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the FitzPatrick acquisition by Generation:
Cash paid for purchase price $110
Cash paid for net cost reimbursement 125
Nuclear fuel transfer 54
Total consideration transferred $289
   
Identifiable assets acquired and liabilities assumed  
Current assets $60
Property, plant and equipment 298
Nuclear decommissioning trust funds 807
Other assets(a)
 114
Total assets $1,279
   
Current liabilities $6
Nuclear decommissioning ARO 444
Pension and OPEB obligations 33
Deferred income taxes 149
Spent nuclear fuel obligation 110
Other liabilities 15
Total liabilities $757
Total net identifiable assets, at fair value $522
   
Bargain purchase gain (after tax) $233
_________
(a)Includes a $110 million asset associated with a contractual rightpre-tax charge to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated with the DOE one-time fee obligation. See Note 23-Commitments and Contingencies of the Exelon 2017 Form 10-K for additional information regarding SNF obligations to the DOE.
Exelon and Generation incurred $16 million and $47 million of merger and integration costs related to FitzPatrick for the three and six months ended June 30, 2017, respectively, which are included within Operating and maintenance expenseexpense.
Completion of the transaction contemplated by the sale agreement is subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and a private letter ruling from the IRS, which was received in Exelon's and Generation's Consolidated StatementsApril 2019. Generation currently anticipates satisfaction of Operations and Comprehensive Income. Exelon and Generation did not incur any merger and integration costs relatedthe remaining closing conditions to FitzPatrick foroccur in the three and six months ended June 30, 2018.second half of 2019.
Other Asset Disposition
In December 2017,On February 28, 2018, Generation entered into an agreement to sellcompleted 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. As a result, as of December 31, 2017, certain assets and liabilities were classified as held for sale and included in the Other current assets and Other current liabilities balances on Exelon's and Generation's Consolidated Balance Sheet. On February 28, 2018, Generation completed the sale of its interestsystems for $87 million, resulting in a pre-tax gain which is included within Gain on sales of assets and businesses onin Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.Income for the three months ended March 31, 2018. In June 2018, additional proceeds were received, and a pre-tax gain was recorded within Gain on sales of assets and businesses onin Exelon's and Generation's Consolidated StatementStatements of Operations and Comprehensive Income.

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

5.4. 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. The performance obligations associated
See Note 3 — Revenue from Contracts with theseCustomers of the Exelon 2018 Form 10-K for additional information regarding the primary sources of revenue are further discussed below.
Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrant's have elected to use the right to invoice practical expedient for the contracts within these revenue categories and generally recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.
Competitive Power Sales (Exelon and Generation)
Generation sells power and other energy-related commodities to both wholesale and retail customers across multiple geographic regions through its customer-facing business, Constellation. Power sale contracts generally contain various performance obligations including the delivery of power and other energy-related commodities such as capacity, ZECs, RECs or other ancillary services. Revenues related to such contracts are generally recognized over time as the power is generated and simultaneously delivered to the customer. However, revenues related to the sale of any goods or services that are not simultaneously received and consumed by the customer are recognized as the performance obligations are satisfied at a point in time. Payment terms generally require that the customers pay for the power or the energy-related commodity within the month following delivery to the customer and there are generally no significant financing components.
Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, the Registrants estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.
Competitive Natural Gas Sales (Exelon and Generation)
Generation sells natural gas on a full requirements basis or for an agreed upon volume to both commercial and residential customers. The primary performance obligation associated with natural gas sale contracts is the delivery of the natural gas to the customer. Revenues related to the sale of natural gas are recognized over time as the natural gas is delivered to and consumed by the customer. Payment from customers is typically due within the month following delivery of the natural gas to the customer and there are generally no significant financing components.
Other Competitive Products and Services (Exelon and Generation)
Generation also sells other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers. These contracts generally contain a single performance obligation, which is the construction and/or installation of the asset for the customer. The average contract term for these projects is approximately 18 months. Revenues, and associated costs, are recognized throughout the contract term using an input method to measure progress towards completion. The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred

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

and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. Payments from customers are typically due within 30 or 45 days from the date the invoice is generated and sent to the customer.
Regulated Electric and Gas Tariff Sales (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
The Utility Registrants sell electricity and electricity distribution services to residential, commercial, industrial and governmental customers through regulated tariff rates approved by their state regulatory commissions. PECO, BGE and DPL also sell natural gas and gas distribution services to residential, commercial, and industrial customers through regulated tariff rates approved by their state regulatory commissions. The performance obligation associated with these tariff sale contracts is the delivery of electricity and/or natural gas. Tariff sales are generally considered daily contracts given that customers can discontinue service at any time. Revenues are generally recognized over time (each day) as the electricity and/or natural gas is delivered to customers. Payment terms generally require that customers pay for the services within the month following delivery of the electricity or natural gas to the customer and there are generally no significant financing components or variable consideration.
Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.
Regulated Transmission Services (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants are members of PJM, the regional transmission organization designated by FERC to coordinate the movement of wholesale electricity in PJM’s region, which includes portions of the mid-Atlantic and Midwest. In accordance with FERC-approved rules, the Utility Registrants and other transmission owners in the PJM region make their transmission facilities available to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants and other transmission owners. The performance obligations associated with the Utility Registrants’ contract with PJM include (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid. These performance obligations are satisfied over time, and Utility Registrants utilize output methods to measure the progress towards their completion. Passage of time is used for NITS and access to the wholesale grid and MWhs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services. PJM pays the Utility Registrants for these services on a weekly basis and there are no financing components or variable consideration.
Costs to Obtain or Fulfill a Contract with a Customer (Exelon and Generation)
Generation incurs incremental costs in order to execute certain retail power and gas sales contracts. These costs primarily relate to retail broker fees and sales commissions. Generation has capitalized such contract acquisition costs in the amount of $28 million and $26 million as of June 30, 2018 and December 31, 2017, respectively, within Other current assets and Other deferred debits in Exelon’s and Generation’s Consolidated Balance Sheets. These costs are capitalized when incurred and amortized using the straight-line method over the average length of such retail contracts, which is approximately 2 years. Exelon and Generation recognized amortization expense associated with these costs in the amount of $5 million and $11 million for the three and six months ended June 30, 2018, respectively, and $8 million and $17 million for the three and six months ended June 30, 2017, respectively, within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Generation does not incur material costs to fulfill contracts

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

with customers that are not already capitalized under existing guidance. In addition, the Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.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. The following table provides a rollforward of the contract assets reflected on Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to June 30, 2018:
Contract Assets Exelon and Generation
Balance as of January 1, 2018 $283
Increases as a result of changes in the estimate of the stage of completion 28
Amounts reclassified to receivables (68)
Balance at June 30, 2018 $243
The Utility Registrants do not have any contract assets.
Contract Liabilities
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’sExelon's and Generation’sGeneration'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 onin Exelon's and Generation's Consolidated Balance SheetSheets from January 1, 2018 to June 30, 2018:March 31, 2019:
Contract Liabilities Exelon and Generation
Balance as of January 1, 2018 $35
Increases as a result of additional cash received or due 298
Amounts recognized into revenues (305)
Balance at June 30, 2018 $28
  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 June 30, 2018March 31, 2019 and December 31, 2017,2018, the Utility Registrants' contract liabilities were immaterial.
Transaction Price Allocated to Remaining Performance Obligations (All Registrants)
The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of June 30, 2018. Generation has elected the exemption which permits the exclusion from thisMarch 31, 2019. This disclosure of certain variable contract consideration. As such, the majority of Generation’s power and gas sales contracts are excluded from this disclosure as they contain variable volumes and/or variable pricing. Thus, this disclosure only

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

includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
The majority ofThis 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’Registrants' gas and electric tariff salesales contracts areand transmission revenue contracts as they generally day-to-day contractshave 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. Further, the Utility Registrants have elected the exemption to not disclose the transaction price allocation to remaining performance obligations for contracts with an original expected duration of one year or less. As such, gas and electric tariff sales contracts and transmission revenue contracts are excluded from this disclosure.
2019 2020 2021 2022 2023 and thereafter Total2019 2020 2021 2022 2023 and thereafter Total
Exelon$574
 $279
 $113
 $46
 $128
 $1,140
$393
 $273
 $112
 $50
 $142
 $970
Generation574
 279
 113
 46
 128
 $1,140
493
 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 1918 — 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.
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Contracted generation●●
Real estate●●●●●●●●●
Vehicles and equipment●●●●●●●●●
(in years)Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Remaining lease terms1-87 1-37 1-34 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/A
Options to terminate within1-3 2 N/A N/A 3 N/A N/A N/A N/A
The components of lease costs for the three months ended March 31, 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
__________
(a)Excludes $3 million, $2 million, $1 million and $1 million of sublease income recorded at Exelon, Generation, PHI and DPL.
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, 2019:
 
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
                  
Operating lease liabilities                 
Other current liabilities249
 173
 3
 1
 31
 36
 8
 11
 6
Other deferred credits and other liabilities1,395
 1,023
 4
 1
 66
 284
 60
 72
 20
Total operating lease liabilities$1,644
 $1,196
 $7
 $2
 $97
 $320
 $68
 $83
 $26
__________
(a)Exelon's and Generation's operating ROU assets and lease liabilities include $631 million and $778 million, respectively, related to contracted generation.
The weighted average remaining lease terms, in years, and discount rates for operating leases as of March 31, 2019 were as follows:
 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%

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:
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)
2019$140
 $33
 $7
 $5
 $35
 $48
 $11
 $14
 $7
2020149
 46
 5
 5
 35
 46
 10
 13
 6
2021143
 46
 4
 5
 33
 43
 9
 12
 5
2022126
 47
 4
 5
 18
 42
 8
 12
 5
202397
 46
 3
 5
 3
 39
 8
 10
 4
Remaining years723
 545
 —
 —
 19
 159
 40
 35
 5
Total minimum future lease payments$1,378
 $763
 $23
 $25
 $143
 $377
 $86
 $96
 $32
__________
(a)Includes amounts related to shared use land arrangements.
(b)Excludes Generation’s contingent operating lease payments associated with contracted generation.
(c)Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd's, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectively. Also includes amounts related to shared use land arrangements.
(d)Includes all future lease payments on a 99-year real estate lease that expires in 2106.
(e)The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022, respectively.
Cash paid for amounts included in the measurement of lease liabilities for the three months ended March 31, 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
ROU assets obtained in exchange for lease obligations for the three months ended March 31, 2019 were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating leases$20
 $9
 $—
 $—
 $—
 $11
 $4
 $4
 $3

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.
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Contracted generation●●
Real estate●●●●●●●●●
(in years)ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Remaining lease terms1-841-331-181-84241-142-713-141-3
Options to extend the term1-791-55-795-50N/A5N/AN/AN/A
The components of lease income for the three months ended March 31, 2019 were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Operating lease income$4
 $3
 $—
 $—
 $—
 $1
 $—
 $1
 $—
Variable lease income$52
 $52
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Future minimum lease payments to be recovered under operating leases as of March 31, 2019 were as follows:
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
 $—

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

6. Regulatory Matters (All Registrants)
Except for the matters noted below, the disclosures set forthAs discussed in Note 34 — Regulatory Matters of the Exelon 20172018 Form 10-K, reflect,the Registrants are involved in all material respects,rate and regulatory proceedings at the currentFERC 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 Date
BGE - Maryland (Natural Gas)June 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, 2019
__________
(a)Requested and approved increases are before New Jersey sales and use tax.
Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateRequested Revenue Requirement Increase/(Decrease) Requested 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 2019
__________
(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.
Transmission Formula Rates
Pending Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. On February 8, 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 active parties filed a status update with the presiding Administrative

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

Law Judge requesting an additional 45 days to file a settlement. PECO cannot predict the outcome of regulatory and legislative proceedingsthis 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 Registrants. tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.
Other State Regulatory Matters
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 allows 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 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 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 begin 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

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

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 million, $51 million, $15 million, $10 million, $3 million, $5 million and $2 million, respectively, as of March 31, 2019.
Regulatory Assets and Liabilities
Regulatory assets and liabilities have not changed materially since December 31, 2018.  See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on the specific regulatory assets and liabilities.
Capitalized Ratemaking Amounts Not Recognized (Exelon and the Utility Registrants)
The following is an updatetable presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that discussion.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)
 ACE
March 31, 2019$64
 $7
 $—
 $49
 $8
 $5
 $3
 $—
December 31, 2018$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
Tax Cuts and Jobs Act (Exelon and ComEd). On January 18, 2018, the ICC approved ComEd's petition filed on January 5, 2018 seeking approval to pass back to customers beginning February 1, 2018 $201 million in tax savings resulting from the enactment of the TCJA through a reduction in electric distribution rates. The amounts being passed back to customers reflect the benefit of lower income tax rates beginning January 1, 2018 and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. See Note 12 — Income Taxes for additional information on Corporate Tax Reform.
Electric Distribution Formula Rate (Exelon and ComEd). On April 16, 2018, ComEd filed its annual distribution formula rate update with the ICC. The filing establishes the revenue requirement used to set the rates that will take effect in January 2019 after the ICC’s review and approval, which is due by December 2018. The revenue requirement requested is based on 2017 actual costs plus projected 2018 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2017 to the actual costs incurred that year. ComEd's 2018 filing request includes a total decrease to the revenue requirement of $23 million, reflecting a decrease of $58 million for the initial revenue requirement for 2018 and an increase of $35 million related to the annual reconciliation for 2017. The revenue requirement for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2017 provided for a weighted average debt and equity return on distribution rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory

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

assets associated with its electric distribution formula rate. See Note 3 — Regulatory Matters of the Exelon 2017 Form 10-K for additional information on ComEd's distribution formula rate filings.
During the first quarter 2018, ComEd revised its electric distribution formula rate, as provided for by FEJA, to reduce the ROE collar calculation from plus or minus 50 basis points to 0 basis points beginning with the reconciliation filed in 2018 for the 2017 calendar year. This revision effectively offsets the favorable or unfavorable impacts to ComEd's electric distribution formula rate revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer. ComEd began reflecting the impacts of this change in its electric distribution formula rate regulatory asset in the first quarter 2017.
Energy Efficiency Formula Rate (Exelon and ComEd). On June 1, 2018, ComEd filed its annual energy efficiency formula rate update with the ICC. The filing establishes the 2019 application year revenue requirement used to set the rates that will take effect in January 2019 after the ICC’s review and approval, which is due by December 2018. The revenue requirement requested is based on 2017 actual costs plus projected 2018 and 2019 expenditures as well as an annual reconciliation of the revenue requirement in effect in 2017 to the actual costs incurred that year. ComEd's 2018 filing request includes a total increase to the revenue requirement of $39 million, reflecting an increase of $38 million for the initial revenue requirement for 2018 and an increase of $1 million related to the annual reconciliation for 2017. The revenue requirement for the 2019 application year provides for a weighted average debt and equity return on rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points.
Zero Emission Standard (Exelon, Generation and ComEd).Standard. Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton unitUnit 1, Quad Cities unitUnit 1 and Quad Cities unitUnit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue. Winning bidders are entitled torevenue with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. During the three months ended June 30,March 31, 2018, Generation recognized revenue of $52 million. During the six months ended June 30, 2018, Generation recognized revenue of $254$150 million of which $150 millionrevenue related to ZECs generated from June 1, 2017 through December 31, 2017.
ComEd recovers all costs associated with purchasing ZECs through a rate rider that provides for an annual reconciliation and true-up to actual costs incurred by ComEd to purchase ZECs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods with interest. ComEd began billing its retail customers under its new ZEC rate rider on June 1, 2017.
On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. One lawsuit was filed by customers of ComEd, led by the Village of Old Mill Creek, and the other was brought by the EPSA and three other electric suppliers. Both lawsuits argueargued that the Illinois ZEC program willwould distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices and seeksought a permanent injunction preventing the implementation of the program. Exelon intervened and filed motions to dismiss in both lawsuits. In addition, on March 31, 2017, plaintiffs in bothThe lawsuits filed motions for preliminary injunction with the court; the court stayed briefing on the motions for preliminary injunction until the resolution of the motions to dismiss. On July 14, 2017,were dismissed by the district court granted the motions to dismiss.on July 14, 2017. On July 17, 2017, the plaintiffs appealed the decision to the Seventh Circuit. Briefs were fully submitted on December 12, 2017, the Court heard oral argument on January 3, 2018. At the argument, the Court asked for supplemental briefing, which was filed on January 26, 2018. On February 21,September 13, 2018, the Seventh Circuit issued an order inviting the Solicitor General to express the views of the United States on the matter. On May 29, 2018, the Solicitor General and FERC filed its brief in the SeventhU.S. Circuit Court of Appeals stating thatfor the Illinois ZEC program does not violate federal law or interfereSeventh Circuit affirmed the lower court's dismissal of both lawsuits. On January 7, 2019, plaintiffs filed a petition seeking U.S. Supreme Court review of the case which was denied on April 15, 2019.

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

with FERC’s authority to regulate wholesale power markets. The Illinois Attorney General, EPSA and Exelon have all filed responses to the Solicitor General’s brief. The appeal of the Illinois ZEC program remains pending in the Seventh Circuit. Exelon cannot predict the outcome of these lawsuits. It is possible that resolution of these matters could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, cash flows, and financial positions.
See Note 8 — Early Plant Retirements for additional information regarding the economic challenges facing Generation’s Clinton and Quad Cities nuclear plants and the expected benefits of the ZES.
Pennsylvania Regulatory Matters
2018 Pennsylvania Electric Distribution Base Rate Case (Exelon and PECO). On March 29, 2018, PECO filed a request with the PAPUC seeking approval to increase its electric distribution base rates by $82 million beginning January 1, 2019. This requested amount includes the effect of an approximately $71 million reduction as a result of the ongoing annual tax savings beginning January 1, 2019 associated with the TCJA. The requested ROE is 10.95%. PECO expects a decision on its electric distribution rate case proceeding in the fourth quarter of 2018 but cannot predict what increase, if any, the PAPUC will approve.
Tax Cuts and Jobs Act (Exelon and PECO). As part of the rate case filing referenced above, PECO is seeking approval to pass back to electric distribution customers $68 million in 2018 TCJA tax savings, which would be an additional offset to the proposed increase to its electric distribution rates. The amounts being proposed to be passed back to customers reflect the respective annual benefits of lower income tax rates established upon enactment of the TCJA. PECO cannot predict the amount or timing of the refunds the PAPUC will ultimately approve.
On May 17, 2018, the PAPUC issued an order to all Pennsylvania utility companies, including PECO, requiring that the annual tax savings beginning on January 1, 2018 associated with TCJA be passed back to customers. The order directs Pennsylvania utility companies without an existing base rate case, including PECO’s gas distribution business, to start passing back the savings from January 1, 2018 onward through a negative surcharge mechanism to be effective on July 1, 2018. Pursuant to the May 17, 2018 Order, PECO filed a negative surcharge mechanism and began on July 1, 2018, to return an estimated $4 million in annual 2018 tax savings to its natural gas distribution customers. For Pennsylvania utility companies with existing base rate cases, including PECO’s electric distribution base rate case, the timing of when and how to pass the annual TCJA savings to customers will be resolved through the base rate case proceeding.
See Note 12 — Income Taxes for additional information on Corporate Tax Reform and the table below for regulatory liabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer rates.
Maryland Regulatory Matters
Tax Cuts and Jobs Act (Exelon, BGE, PHI, Pepco and DPL).  On January 12, 2018, the MDPSC issued an order that directed each of BGE, Pepco and DPL to track the impacts of the TCJA beginning January 1, 2018 and file by February 15, 2018 how and when they expect to pass through such impacts to their customers.
On January 31, 2018, the MDPSC approved BGE's petition to pass back to customers $103 million in ongoing annual tax savings resulting from the enactment of the TCJA through a reduction in distribution base rates beginning February 1, 2018, of which $72 million and $31 million were related to electric and natural gas, respectively. The amounts being passed back to customers reflect the ongoing annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. BGE's natural gas distribution rate case filing in June

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

2018 included a request to provide to customers the natural gas portion of the January 2018 TCJA savings over a 5-year period.
On April 20, 2018, Pepco entered into a settlement agreement with several parties to resolve all issues in its pending electric distribution base rate case, including the treatment of the annual ongoing TCJA tax savings as well as the TCJA tax savings from January 1, 2018 through the expected effective date of the rate change. On May 31, 2018, the MDPSC issued an order approving the settlement agreement with an effective date of June 1, 2018. See discussion below for additional information.
On February 9, 2018, DPL filed with the MDPSC seeking approval to pass back to customers $13 million in ongoing annual TCJA tax savings through a reduction in electric distribution base rates beginning in 2018. On April 18, 2018, the MDPSC approved a settlement agreement to pass back to customers $14 million in ongoing annual TCJA tax savings through a reduction in electric distribution base rates beginning April 20, 2018. The amounts being passed back to customers reflect the ongoing annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. In addition, the MDPSC separately ordered DPL to provide a one-time bill credit to customers of $2 million in June 2018 representing the TCJA tax savings from January 1, 2018 through March 31, 2018.
See Note 12 — Income Taxes for additional information on Corporate Tax Reform and the table below for regulatory liabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer rates.
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). On December 1, 2017 (and as amended on January 22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated surcharge, subject to BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and the associated surcharge will be effective in rates beginning in January 2019. The new five-year plan calls for capital expenditures over the 2019-2023 timeframe of $732 million, with an associated revenue requirement of $200 million.
2018 Maryland Natural Gas Distribution Base Rates (Exelon and BGE). On June 8, 2018, BGE filed an application with the MDPSC to increase natural gas revenues by $63 million, reflecting a requested ROE of 10.5%. BGE expects a decision in the first quarter of 2019 but cannot predict how much of the requested increase the MDPSC will approve.
2018 Maryland Electric Distribution Base Rates (Exelon, PHI and Pepco).  On January 2, 2018, Pepco filed an application with the MDPSC to increase its annual electric distribution base rates by $41 million, reflecting a requested ROE of 10.1%. On February 5, 2018, Pepco filed with the MDPSC an update to its current distribution base rate case to reflect $31 million in ongoing annual TCJA tax savings, thereby reducing the requested annual base rate increase to $11 million. On March 8, 2018, Pepco filed with the MDPSC a subsequent update to its electric distribution base rate case, which further reduced the requested annual base rate increase to $3 million. On April 20, 2018, Pepco entered into a settlement agreement with several parties to resolve all issues in the rate case and filed the settlement agreement with the MDPSC. The settlement agreement provides for a net decrease to annual electric distribution base rates of $15 million, which includes annual ongoing TCJA tax savings, and reflects a ROE of 9.5%. In addition, the settlement agreement separately provides a one-time bill credit to customers of approximately $10 million representing the TCJA tax savings from January 1, 2018 through the expected rate effective date of June 1, 2018. On May 31, 2018, the MDPSC issued an order approving the settlement agreement with an effective date of June 1, 2018.
2017 Maryland Electric Distribution Base Rates (Exelon, PHI and DPL). On July 14, 2017, DPL filed an application with the MDPSC to increase its annual electric distribution base rates by $27

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

million, which was updated to $19 million on November 16, 2017, reflecting a requested ROE of 10.1%. On December 18, 2017, a settlement agreement was filed with the MDPSC wherein DPL will be granted a base rate increase of $13 million, and a ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs. On February 9, 2018, the MDPSC approved the settlement agreement and the new rates became effective.
In the second quarter of 2018, DPL discovered a rate design issue in Maryland such that the current rates are not sufficient to collect the full amount of the $13 million revenue increase agreed to by the parties in the recent settlement. DPL is in discussion with the parties to determine the appropriate resolution to this issue but cannot predict when it will be decided.
Delaware Regulatory Matters
Tax Cuts and Jobs Act (Exelon, PHI and DPL).  On January 16, 2018, the DPSC opened a docket indicating that DPL’s TCJA tax savings would be addressed in its pending rate cases. See discussion below for further information on the proposed treatment of the TCJA tax savings in DPL’s pending electric and natural gas distribution base rate cases.
2017 Delaware Electric and Natural Gas Distribution Base Rates (Exelon, PHI and DPL). In 2017 (as updated on February 9, 2018 to reflect $19 million and $7 million of ongoing annual TCJA tax savings for electric and natural gas, respectively), DPL filed applications with the DPSC to increase its annual electric and natural gas distribution base rates by $12 million and $4 million, respectively, reflecting a requested ROE of 10.1%. The ongoing annual TCJA tax savings reflect the ongoing annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. Of the proposed electric and natural gas rate increases, $2.5 million of each were put into effect in the fourth quarter 2017 and an additional $3 million and $1 million, respectively, were put into effect in the first quarter 2018, all of which are subject to refund based on the final DPSC order.
On June 27, 2018, DPL entered into a settlement agreement with all active parties in the proceeding related to its pending electric distribution base rate case. The settlement agreement provides for a net decrease to annual electric distribution base rates of $7 million, which includes annual ongoing TCJA tax savings, and reflects a ROE of 9.7%. In addition, the settlement agreement separately provides a one-time bill credit to customers of approximately $3 million representing the TCJA tax savings from February 1, 2018 through March 17, 2018, when full interim rates were put into effect. A decision is expected on the matter in the third quarter of 2018, with a rate refund expected to be issued in the fourth quarter of 2018 if the DPSC approves the settlement agreement as filed. DPL expects a decision on its natural gas distribution base rate proceeding in the fourth quarter of 2018 but cannot predict how much of the requested increase the DPSC will approve.
See Note 12 — Income Taxes for additional information on Corporate Tax Reform and the table below for regulatory liabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer rates.
District of Columbia Regulatory Matters
Tax Cuts and Jobs Act (Exelon, PHI and Pepco).  On January 23, 2018, the DCPSC opened a rate proceeding directing Pepco to track the impacts of the TCJA beginning January 1, 2018 and file its plan to reduce the current revenue requirement by customer class by February 12, 2018. The DCPSC stated it will address the impact of the TCJA on future rates within Pepco's pending electric distribution base rate case discussed below.
On February 6, 2018, Pepco filed with the DCPSC seeking approval to pass back to customers $39 million in ongoing annual tax savings resulting from the enactment of the TCJA through a reduction

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

to existing electric distribution base rates beginning in 2018. On April 17, 2018, Pepco entered into a settlement agreement with several parties to resolve all issues in its pending electric distribution base rate case, including the treatment of the annual ongoing TCJA tax savings as well as the TCJA tax savings from January 1, 2018 through the expected effective date of the rate change. See discussion below for additional information.
2017 District of Columbia Electric Distribution Base Rates (Exelon, PHI and Pepco).   On December 19, 2017 (and updated on February 9, 2018), Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $66 million, reflecting a requested ROE of 10.1%. On April 17, 2018, Pepco entered into a settlement agreement with several parties to resolve both the pending electric distribution base rate case and the $39 million rate reduction request in the TCJA proceeding discussed above and filed the settlement agreement with the DCPSC. The settlement agreement provides for a net decrease to annual electric distribution rates of $24 million, which includes annual ongoing TCJA tax savings, and a ROE of 9.525%. The parties to the settlement agreement have requested that Pepco’s new rates be effective on July 1, 2018. In addition, the settlement agreement separately provides a one-time bill credit to customers of approximately $19 million representing the TCJA benefits for the period January 1, 2018 through the expected rate effective date of July 1, 2018. Pepco expects a decision in this matter in the third quarter of 2018.
See Note 12 — Income Taxes for additional information on Corporate Tax Reform and the table below for regulatory liabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer rates.
New Jersey Regulatory Matters
Tax Cuts and Jobs Act (Exelon, PHI and ACE). On January 31, 2018, the NJBPU issued an order mandating that New Jersey utility companies, including ACE, pass any economic benefit from the TCJA to rate payers. The order directed New Jersey utility companies to file by March 2, 2018 proposed tariff sheets reflecting TCJA benefits, with new rates to be implemented in two phases. In addition, the NJBPU directed New Jersey utility companies to file by March 2, 2018 a Petition with the NJBPU outlining how they propose to refund any over-collection associated with revised rates not being in place from January 1, 2018 through March 31, 2018, with interest.
On March 2, 2018, ACE filed with the NJBPU seeking approval to pass back to customers $23 million in ongoing annual TCJA tax savings through a reduction in electric distribution base rates beginning in 2018. The amounts being passed back to customers would reflect the ongoing annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. On March 26, 2018, the NJBPU issued an order accepting ACE’s proposed bill reduction related to the lower income tax rates. A portion of the annual decrease in electric distribution base rates totaling approximately $13 million was effective as of April 1, 2018, but considered interim, and the proposed final annual decrease in electric distribution base rates of $23 million, which includes the settlement of the deferred income tax regulatory liability, is still in settlement discussions. It is expected that the NJBPU will address in a future rate proceeding ACE's treatment of the TCJA tax savings for the period January 1, 2018 through July 1, 2018.
See Note 12 — Income Taxes for additional information on Corporate Tax Reform and the table below for regulatory liabilities recognized during 2018 associated with TCJA tax savings that will be passed through future customer rates.
ACE Infrastructure Investment Program Filing (Exelon, PHI and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s Infrastructure Investment Program (IIP) proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. ACE currently expects a decision

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

in this matter in the first quarter of 2019 but cannot predict if the NJBPU will approve the application as filed.
Update and Reconciliation of Certain Over and Under Recovered Balances (Exelon, PHI and ACE). On February 5, 2018, ACE submitted its 2018 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the non-utility generators and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollectible accounts. As filed, the net impact of adjusting the charges as proposed would have been an overall annual rate decrease of $19 million, including New Jersey sales and use tax. On May 22, 2018, the NJBPU approved a stipulation of settlement among certain interested parties providing for an overall annual rate decrease of $33 million, effective June 1, 2018. The rate decrease was placed into effect provisionally, subject to a review by the NJBPU and the Division of Rate Counsel of the final underlying costs for reasonableness and prudence. This rate decrease will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism. The matter is pending at the NJBPU.
New Jersey Clean Energy Legislation (Exelon, Generation and ACE).Legislation. On May 23, 2018, the Governor of New Jersey signed newenacted legislation which became effective immediately, that establishes and modifies New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards. The new legislation expands the state's renewable portfolio standard to require that 50% of electric generation sold be from renewable energy sources by 2030; modifies the New Jersey solar renewable energy portfolio standard to require that 5.1% of electric generation sold in New Jersey be from solar electric power by 2021, lowers the solar alternative compliance payment amount starting in 2019 and requires the NJBPU to adopt rules to replace the current solar renewable energy credit program; and requires the NJBPU to increase its offshore wind energy credit program to 3,500 MW. The new legislation further imposes an energy efficiency standard that each electric public utility will be required to reduce annual usage by 2% and provides for utilities to annually file for recovery of the costs of the programs, including the revenue impact of sales losses resulting from the programs. The NJBPU is required to initiate a study to determine the savings targets for each public utility, to adopt other rules regarding the programs, and to approve energy efficiency and peak demand reduction programs for each utility. The new legislation also requires the NJBPU to conduct an energy storage analysis including the potential costs and benefits and to initiate a proceeding to establish a goal of achieving 2,000 MW of energy storage by 2030; requires the utilities to conduct a study on voltage optimization on their distribution system; and requires the NJBPU to establish a community solar program to permit customers to participate in a solar project that is not located on the customer’s property.
On the same day, the Governor of New Jersey also signed new legislation, which became effective immediately, that will establishestablished a ZEC program providingthat 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. PSEG’s Salem nuclear plant is expected to apply for approval to participate in the ZEC program. Under the new legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. The
On November 19, 2018, NJBPU has 180 days fromissued an order providing for the effective date to establish proceduresmethod and application process for implementationdetermining the eligibility of the ZEC program and 330 days from the effective date to determine which nuclear power plants, are selected to receive ZECs undera draft method and process for ranking and selecting eligible nuclear power plants, and the program. Selected nuclear plants will receive ZEC paymentsestablishment of a mechanism for each energy year (12-month periodregulated utility to purchase ZECs from June 1 through May 31) within 90 days after the completion of such energy year. The quantity of ZECs issued will be determined based on the greater of 40% of the total number of MWh of electricity distributed by the public electric distribution utilities in New Jersey in the prior year, or the total number of MWh of electricity generated in the prior year by the selected nuclear power plants. TheOn 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 price is approximately $10 per MWh duringprogram. On the first 3-year eligibility period. For eligibility periods following

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

the first 3-year eligibility period,same day, Generation filed certain Supplemental Information with the NJBPU has discretionproviding 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 reduce the ZEC price. Electric distribution utilities in New Jersey, including ACE, will be authorized to collect from retail distribution customers through a non-bypassable charge all costs associated with the utility’s procurement of the ZECs.Salem 1 and Salem 2. See Note 8 -— Early Plant Retirements for additional information on New Jersey’s ZEC program potential impacts to PSEG’s Salem nuclear plant.
2018 New Jersey Electric Distribution Base Rates (Exelon, PHI and ACE). On June 15, 2018, ACE submitted an application with the NJBPU to increase its annual electric distribution base rates by approximately $99.7 million (before New Jersey sales and use tax), based upon a requested ROE of 10.1%. Included in the $99.7 million request is $40 million of higher depreciation expense related to ACE's updated depreciation study. On July 25, 2018, the NJBPU dismissed ACE’s base rate case due to the number of forecasted months included in the twelve month test period. Historically, ACE and other New Jersey utilities have filed distribution base rate cases with a similar number of forecasted months in the test period. ACE expects to file a new application with the NJBPU in the third quarter of 2018 that complies with the required forecasted test period.Salem.
New York Regulatory Matters
New York Clean Energy Standard (Exelon and Generation).Standard. On August 1, 2016, the New York Public Service Commission (NYPSC)NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC. The ZEC price for the first tranche has been set at $17.48 per MWh of production. Following the first tranche, the price will be updated bi-annually.
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.competitors, which was dismissed by the district court on July 25, 2017. On December 9, 2016, Generation and CENGSeptember 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 motion to intervene inpetition seeking U.S. Supreme Court review of the case and to dismiss the lawsuit. The State also filed a motion to dismiss. On July 25, 2017, the court granted both motions to dismiss. On August 24, 2017, plaintiffs appealed the decision to the Second Circuit. Plaintiffs-Appellants' initial briefwhich was fileddenied on October 13, 2017. Briefing in the appeal was completed in December 2017 and oral argument was held on March 12, 2018. On May 29, 2018, Generation and CENG provided the court with a copy of the brief submitted by the Solicitor General and FERC in the Seventh Circuit ZEC litigation stating that that the Illinois ZEC program does not violate federal law. The Plaintiffs-Appellants’ subsequent response to the brief and our answer to that response also have been provided to the Second Circuit.April 15, 2019.
In addition, on November 30, 2016 (as amended on January 13, 2017), a group of parties including certain environmental groups and individuals, filed a Petition in New York State court seeking to invalidate the ZEC program. The Petition,program, which was amended on January 13, 2017, 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 (SAPA) when adopting the ZEC program. On February 15, 2017,Subsequently, Generation, CENG and CENGthe NYPSC filed a motionmotions to dismiss the state court action. The NYPSC also filed a motion to dismissaction, which were later opposed by the state court action. On March 24, 2017, the plaintiffs filed a memorandum of law opposing the motions to dismiss, and Generation and CENG filed a reply brief on April 28, 2017. Oral argument was held on June 19, 2017.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. The case is now proceeding to summary judgment with the full record. Exelon’sGeneration, CENG and the state’s answers and briefs were filed on March 30, 2018. Plaintiffs’ responses were due on May 11, 2018; however, on AprilOn December 17, 2018, Plaintiffs’plaintiffs filed an ordera reply brief introducing new arguments and new evidence. The State of New York filed a motion to show cause seeking production of additional documents, including confidential financial information. Exelonstrike on December 28, 2018. On January 4, 2019, Generation and CENG filed a motion to strike the state filed in opposition to the order to show cause. On July 18,

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

2018, thenew arguments and new evidence.The court denied the order to show cause and ordered the parties to provide the court within 20 days with an agreed upon final schedule for the remaining brief. After briefing is completed, the court willmust now decide whether or not to set the case for hearing.
Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 8 — Early Plant Retirements for additional information relativerelated to Ginna and Nine Mile Point.
Federal Regulatory Matters
Tax Cuts and Jobs Act and Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). Pursuant to their respective transmission formula rates, ComEd, PECO, BGE, Pepco, DPL and ACE began passing back to customers on June 1, 2018, the benefit of lower income tax rates effective January 1, 2018. ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s transmission formula rates currently do not provide for the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA.
On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. 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. On December 18, 2017, BGE filed for clarification and rehearing of FERC’s order, still seeking full recovery of its existing transmission-related income tax regulatory asset amounts.
On February 27, 2018 (and updated on March 26, 2018), BGE submitted a letter to FERC advising that the lower federal corporate income tax rate effective January 1, 2018 provided for in TCJA will be reflected in BGE’s annual formula rate update effective June 1, 2018, but that the deferred income tax benefits will not be passed back to customers unless BGE’s formula rate is revised to provide for pass back and recovery of transmission-related income tax-related regulatory liabilities and assets.
ComEd, Pepco, DPL and ACE have similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval. On February 23, 2018, ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to facilitate passing back to customers ongoing annual TCJA tax savings and to permit recovery of transmission-related income tax regulatory assets. The companies requested the revisions be effective as of April 24, 2018. On April 24, 2018, the FERC issued a letter indicating that the filings were deficient and requiring the parties to file additional information. On July 9, 2018, each of ComEd, Pepco, DPL and ACE submitted such additional information. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula and, thus, are not impacted by BGE’s November 16, 2017 FERC order. See below for additional information regarding PECO's transmission formula rate filing.
Each of BGE, ComEd, Pepco, DPL and ACE believe there is sufficient basis to support full recovery of their existing transmission-related income tax regulatory assets, as evidenced by the further pursuit of full recovery with FERC. However, upon further consideration of the November 16, 2017 FERC order, management of each company concluded that the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery was no longer probable of recovery. As a result, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE recorded charges to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017, reducing their associated transmission-related income tax regulatory assets.
If any of the companies are ultimately successful with FERC allowing future recovery of these amounts, the associated regulatory assets will be reestablished, with corresponding decreases to Income

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

tax expense. To the extent all or a portion of the prospective amortization amounts were no longer considered probable of recovery, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be up to approximately $84 million, $42 million, $23 million, $19 million, $9 million, $7 million and $3 million, respectively, as of June 30, 2018.
The Utility Registrants cannot predict the outcome of these FERC proceedings.
Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2018 annual electric transmission formula rate updates.
 2018
Annual Transmission Updates(a)(b)
ComEd BGE Pepco DPL ACE
Initial revenue requirement (decrease) increase$(44) $10
 $6
 $14
 $4
Annual reconciliation increase (decrease)18
 4
 2
 13
 (4)
Dedicated facilities increase(c)
—
 12
 —
 —
 —
Total revenue requirement (decrease) increase$(26) $26
 $8
 $27
 $—
          
Allowed return on rate base(d)
8.32% 7.61% 7.82% 7.29% 8.02%
Allowed ROE(e)
11.50% 10.50% 10.50% 10.50% 10.50%
__________
(a)All rates are effective June 2018, subject to review by the FERC and other parties, which is due by fourth quarter 2018.
(b)The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA.  See further discussion above. 
(c)BGE's transmission revenues include a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to a specifically designated load by BGE.
(d)Represents the weighted average debt and equity return on transmission rate bases.
(e)As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization.
See Note 3 - Regulatory Matters of the Exelon 2017 Form 10-K for additional information regarding transmission formula rate updates.
Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the final outcome of this proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a revenue decrease of $6 million. The revenue

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

decrease of $6 million included an approximately $20 million reduction as a result of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.
PJM Transmission Rate Design (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). On June 15, 2016, a number of parties, including the Utility Registrants, filed a proposed settlement with FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. The settlement included provisions for monthly credits or charges related to the periods prior to January 1, 2016 that are expected to be refunded or recovered through PJM wholesale transmission rates through December 2025.
On May 31, 2018, FERC issued an order approving the settlement and directed PJM to adjust wholesale transmission rates within 30 days. Pursuant to the order, similar charges for the period January 1, 2016 through June 30, 2018 will also be refunded or recovered through PJM wholesale transmission rates over the subsequent 12-month period. PJM will commence billing the refunds and charges associated with this settlement in August 2018. The Utility Registrants expect to refund or recover these settlement amounts through prospective electric distribution customer rates. On July 2, 2018, a number of parties filed petitions for rehearing or clarification.
Pursuant to the FERC approval of the settlement and the expected refund or recovery of the associated amounts from electric distribution customers, in the second quarter of 2018, the Utility Registrants recorded the following payables to/receivables from PJM and related regulatory assets/liabilities. Generation recorded a $23 million net payable to PJM and a pre-tax charge within Purchased power and fuel expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
 PJM Receivable PJM Payable Regulatory Asset Regulatory Liability
Exelon$197
 $158
 $136
 $198
Generation—
 23
 —
 —
ComEd99
 —
 —
 99
PECO85
 —
 —
 85
BGE—
 51
 51
 —
PHI(a)
13
 84
 85
 14
Pepco—
 84
 84
 —
DPL10
 —
 —
 10
ACE3
 —
 1
 4
__________
(a)PHI reflects the consolidated impacts of Pepco, DPL, and ACE.
Operating License Renewals (Exelon and Generation).
Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-yearnew license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) with Maryland Department of the Environment (MDE) for Conowingo, Generation continues to work with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.
On April 21, 2016, Generation and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a Settlement Agreement resolving all fish passage issues between the parties. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the 46-year life of the new license, including both capital and operating costs. The actual

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

timing and amount of these costs are not currently fixed and may vary significantly from year to year throughout the life of the new license.
On April 27, 2018, the MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, unfavorable impact onin Exelon’s and Generation’s results of operations, cash flows and financial positionsstatements through an increase in capital expenditures and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous violating MDE regulations, state, federal, and constitutional law. Generation also requested that FERC defer action onthe 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 proposed by MDE in April 2018. Exelon also continues to challenge the 401 Certification through the administrative process and in state and federal court. Exelon and Generation cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
As of June 30, 2018, $34March 31, 2019, $38 million of direct costs associated with Conowingo licensing efforts have been capitalized. See Note 34 — Regulatory Matters of the Exelon 20172018 Form 10-K for additional information on Generation's operating license renewal efforts.
On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom units 2 and 3. Generation anticipates the second license renewal process to take approximately 2 years from the application submission until completion of the NRC’s review process. Peach Bottom units 2 and 3 are licensed to operate through 2033 and 2034, respectively.
Regulatory Assets and Liabilities (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE each prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

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

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of June 30, 2018 and December 31, 2017. See Note 3 — Regulatory Matters of the Exelon 2017 Form 10-K for additional information on the specific regulatory assets and liabilities.
June 30, 2018Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory assets               
Pension and other postretirement benefits(a)
$3,777
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Deferred income taxes363
 —
 353
 —
 10
 10
 —
 —
AMI programs(c)
602
 147
 30
 203
 222
 149
 73
 —
Electric distribution formula rate(d)
243
 243
 —
 —
 —
 —
 —
 —
Energy efficiency costs284
 284
 —
 —
 —
 —
 —
 —
Debt costs105
 35
 1
 11
 69
 14
 7
 5
Fair value of long-term debt730
 —
 —
 —
 594
 —
 —
 —
Fair value of PHI's unamortized energy contracts638
 —
 —
 —
 638
 —
 —
 —
Asset retirement obligations113
 76
 22
 15
 —
 —
 —
 —
MGP remediation costs276
 257
 19
 —
 —
 —
 —
 —
Under-recovered uncollectible accounts61
 61
 —
 —
 —
 —
 —
 —
Renewable energy252
 252
 —
 —
 —
 —
 —
 —
Energy and transmission programs(e)(f)(g)(h)(i)(j)
249
 8
 37
 75
 129
 90
 14
 25
Deferred storm costs44
 —
 —
 —
 44
 10
 4
 30
Energy efficiency and demand response programs552
 —
 1
 267
 284
 206
 78
 —
Merger integration costs(k)(l)(m)
45
 —
 —
 4
 41
 19
 12
 10
Under-recovered revenue decoupling(n)
37
 —
 —
 9
 28
 28
 —
 —
COPCO acquisition adjustment4
 —
 —
 —
 4
 —
 4
 —
Workers compensation and long-term disability costs34
 —
 —
 —
 34
 34
 —
 —
Vacation accrual30
 —
 16
 —
 14
 —
 8
 6
Securitized stranded costs64
 —
 —
 —
 64
 —
 —
 64
CAP arrearage11
 —
 11
 —
 —
 —
 —
 —
Removal costs545
 —
 —
 —
 545
 153
 95
 298
DC PLUG charge179
 —
 —
 —
 179
 179
 —
 —
Other78
 8
 12
 6
 52
 38
 11
 3
Total regulatory assets9,316
 1,371
 502
 590
 2,951
 930
 306
 441
Less: current portion1,293
 237
 75
 185
 512
 248
 64
 60
Total noncurrent regulatory assets$8,023
 $1,134
 $427
 $405
 $2,439
 $682
 $242
 $381

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

June 30, 2018Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory liabilities               
Other postretirement benefits$22
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Deferred income taxes(b)
5,118
 2,435
 —
 1,009
 1,674
 768
 497
 409
Nuclear decommissioning2,915
 2,430
 485
 —
 —
 —
 —
 —
Removal costs1,560
 1,353
 —
 79
 128
 20
 108
 —
Deferred rent34
 —
 —
 —
 34
 —
 —
 —
Energy efficiency and demand response programs11
 5
 4
 —
 2
 —
 —
 2
DLC program costs7
 —
 7
 —
 —
 —
 —
 —
Electric distribution tax repairs19
 —
 19
 —
 —
 —
 —
 —
Gas distribution tax repairs7
 —
 7
 —
 —
 —
 —
 —
Energy and transmission programs(e)(f)(g)(h)(i)(j)
336
 154
 139
 15
 28
 —
 18
 10
Over-recovered revenue decoupling(n)
19
 —
 —
 19
 —
 —
 —
 —
Renewable portfolio standards costs106
 106
 —
 —
 —
 —
 —
 —
Zero emission credit costs11
 11
 —
 —
 —
 —
 —
 —
Over-recovered uncollectible accounts9
 —
 —
 —
 9
 —
 —
 9
Merger integration costs(l)
3
 —
 —
 —
 3
 —
 3
 —
TCJA income tax benefit over-recoveries(o)
94
 —
 31
 18
 45
 29
 7
 9
Other107
 14
 21
 36
 36
 4
 22
 8
Total regulatory liabilities10,378
 6,508
 713
 1,176
 1,959
 821
 655
 447
Less: current portion701
 287
 168
 106
 125
 30
 67
 29
Total noncurrent regulatory liabilities$9,677
 $6,221
 $545
 $1,070
 $1,834
 $791
 $588
 $418

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

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

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

__________
(a)Includes regulatory assets established at the Constellation and PHI merger dates of $414 million and $915 million, respectively, as of June 30, 2018 and $440 million and $953 million, respectively, as of December 31, 2017 related to the rate regulated portions of the deferred costs associated with legacy Constellation’s and PHI’s pension and other postretirement benefit plans that are being amortized and recovered over approximately 12 years and 3 to 15 years, respectively (as established at the respective acquisition dates). The Utility Registrants are not earning or paying a return on these amounts.
(b)As of June 30, 2018, includes transmission-related income tax regulatory liabilities that require FERC approval separate from the transmission formula rate of $475 million, $133 million, $136 million, $145 million and $146 million for ComEd, BGE, Pepco, DPL and ACE, respectively. As of December 31, 2017, includes transmission-related income tax regulatory liabilities that require FERC approval separate from the transmission formula rate of $484 million, $137 million, $147 million, $148 million and $147 million for ComEd, BGE, Pepco, DPL and ACE, respectively.
(c)As of June 30, 2018, BGE's regulatory asset of $203 million includes $121 million of unamortized incremental deployment costs under the program, $49 million of unamortized costs of the non-AMI meters replaced under the AMI program, and $33 million related to post-test year incremental program deployment costs incurred prior to approval became effective June 2016. As of December 31, 2017, BGE's regulatory asset of $214 million includes $129 million of unamortized incremental deployment costs under the program, $53 million of unamortized costs of the non-AMI meters replaced under the AMI program, and $32 million related to post-test year incremental program deployment costs incurred prior to approval became effective June 2016. Recovery of the post-test year incremental deployment costs will be addressed in a future base rate proceeding.
(d)As of June 30, 2018, ComEd’s regulatory asset of $243 million was comprised of $180 million for the 2016, 2017 and 2018 annual reconciliations and $63 million related to significant one-time events. As of December 31, 2017, ComEd’s regulatory asset of $244 million was comprised of $186 million for the 2016 and 2017 annual reconciliations and $58 million related to significant one-time events.
(e)As of June 30, 2018, ComEd’s regulatory asset of $8 million represents transmission costs recoverable through its FERC approved formula rate. As of June 30, 2018, ComEd’s regulatory liability of $154 million included $99 million related to the PJM Transmission Rate Design Settlement, $23 million related to over-recovered energy costs and $32 million associated with revenues received for renewable energy requirements. As of December 31, 2017, ComEd’s regulatory asset of $6 million represents transmission costs recoverable through its FERC approved formula rate. As of December 31, 2017, ComEd’s regulatory liability of $47 million included $14 million related to over-recovered energy costs and $33 million associated with revenues received for renewable energy requirements.
(f)As of June 30, 2018, PECO’s regulatory asset of $37 million represents the under-recovered natural gas costs under the PGC. As of December 31, 2017, PECO’s regulatory asset of $1 million is related to under-recovered costs under the TSC program. As of June 30, 2018, PECO's regulatory liability of $139 million included $85 million related to the PJM Transmission Rate Design Settlement, $46 million related to over-recovered costs under the DSP program, $3 million related to the over-recovered transmission service charges and $5 million related to over-recovered non-bypassable transmission service charges. As of December 31, 2017, PECO's regulatory liability of $60 million included $36 million related to over-recovered costs under the DSP program, $12 million related to over-recovered non-bypassable transmission service charges and $12 million related to the over-recovered natural gas costs under the PGC.
(g)As of June 30, 2018, BGE's regulatory asset of $75 million included $51 million related to the PJM Transmission Rate Design Settlement, $14 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $7 million related to under-recovered electric energy costs and $3 million of abandonment costs to be recovered upon FERC approval. As of June 30, 2018, BGE's regulatory liability of $15 million related to over-recovered natural gas costs. As of December 31, 2017, BGE’s regulatory asset of $23 million included $7 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $5 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval and $8 million of under-recovered natural gas costs.
(h)As of June 30, 2018, Pepco's regulatory asset of $90 million included $84 million related to the PJM Transmission Rate Design Settlement, $4 million of transmission costs recoverable through its FERC approved formula rate and $2 million related to under-recovered electric energy costs. As of December 31, 2017, Pepco's regulatory asset of $11 million included $3 million of transmission costs recoverable through its FERC approved formula rate and $8 million of under-recovered electric energy costs.
(i)As of June 30, 2018, DPL's regulatory asset of $14 million included $12 million of transmission costs recoverable through its FERC approved formula rate and $2 million related to under-recovered electric energy costs. As of June 30, 2018, DPL's regulatory liability of $18 million included $10 million related to the PJM Transmission Rate Design Settlement and $8 million related to over-recovered electric energy and gas fuel costs. As of December 31, 2017, DPL's regulatory asset of $15 million included $8 million of transmission costs recoverable through its FERC approved formula rate and $7 million related to under-recovered electric energy costs. As of December 31, 2017, DPL's regulatory liability of $1 million related to over-recovered electric energy costs.
(j)As of June 30, 2018, ACE's regulatory asset of $25 million included $1 million related to the PJM Transmission Rate Design Settlement, $8 million of transmission costs recoverable through its FERC approved formula rate and $16 million of under-recovered electric energy costs. As of June 30, 2018, ACE's regulatory liability of $10 million included $4 million related to the PJM Transmission Rate Design Settlement and $6 million related to over-recovered electric energy costs. As of December 31, 2017, ACE's regulatory asset of $26 million included $11 million of transmission costs recoverable through its FERC approved formula rate and $15 million of under-recovered electric energy costs. As of December 31, 2017, ACE's regulatory liability of $3 million related to over-recovered electric energy costs.
(k)As of June 30, 2018, Pepco’s regulatory asset of $19 million represents previously incurred PHI integration costs, including $10 million authorized for recovery in Maryland and $9 million expected to be recovered in the District of Columbia service territory. As of December 31, 2017, Pepco’s regulatory asset of $20 million represents previously incurred PHI integration costs, including $11 million authorized for recovery in Maryland and $9 million expected to be recovered in the District of Columbia service territory.
(l)As of June 30, 2018, DPL’s regulatory asset of $12 million represents previously incurred PHI integration costs, including $4 million authorized for recovery in Maryland, $4 million authorized for recovery in Delaware electric rates, $2 million authorized for recovery in Delaware gas rates and $2 million expected to be recovered in electric rates in the Delaware and Maryland service territories. As of June 30, 2018, DPL’s regulatory liability of $3 million represents net synergy savings incurred related to PHI integration costs that are expected to be returned in electric and gas rates in the Delaware service territory. As of December 31, 2017, DPL’s regulatory

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

asset of $10 million represents previously incurred PHI integration costs, including $4 million authorized for recovery in Maryland, $5 million authorized for recovery in Delaware electric rates, and $1 million expected to be recovered in electric and gas rates in the Maryland and Delaware service territories.
(m)As of June 30, 2018 and December 31, 2017, ACE’s regulatory asset of $10 million and $9 million, respectively, represents previously incurred PHI integration costs expected to be recovered in the New Jersey service territory.
(n)Represents the electric and natural gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of June 30, 2018, BGE had a regulatory asset of $9 million related to under-recovered electric revenue decoupling and a regulatory liability of $19 million related to over-recovered natural gas revenue decoupling. As of December 31, 2017, BGE had a regulatory asset of $10 million related to under-recovered electric revenue decoupling and $4 million related to under-recovered natural gas revenue decoupling.
(o)Represents over-recoveries related to the change in the federal income tax rate with the enactment of the TCJA. These regulatory liabilities will be amortized as the TCJA income tax benefits are passed back to customers. See Tax Cuts and Jobs Act disclosures above for additional information on the regulatory proceedings.
Capitalized Ratemaking Amounts Not Recognized (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes on Exelon's, ComEd's, PECO's, BGE's, PHI's, Pepco's, DPL's and ACE'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)
 ACE
June 30, 2018$67
 $7
 $—
 $51
 $9
 $5
 $4
 $—
                
 Exelon 
ComEd(a)
 PECO 
BGE(b)
 PHI 
Pepco(c)
 
DPL(c)
 ACE
December 31, 2017$69
 $6
 $—
 $53
 $10
 $6
 $4
 $—
_________
(a)Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its 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.
Purchase of Receivables Programs (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
ComEd, PECO, BGE, Pepco, DPL and ACE are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from retail electric and natural gas suppliers that participate in the utilities' consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and is permitted to recover uncollectible accounts expense, including those from Third Party Suppliers, from customers through distribution rates. ACE purchases receivables at face value. ACE recovers all uncollectible accounts expense, including those from Third Party Suppliers, through the Societal Benefits Charge (SBC) rider, which includes uncollectible accounts expense as a component. The SBC is filed annually with the NJBPU. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of June 30, 2018 and December 31, 2017.

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

As of June 30, 2018Exelon ComEd PECO BGE PHI Pepco DPL ACE
Purchased receivables$305
 $98
 $66
 $54
 $87
 $59
 $8
 $20
Allowance for uncollectible accounts(a)
(31) (15) (4) (3) (9) (5) (1) (3)
Purchased receivables, net$274
 $83
 $62
 $51
 $78
 $54
 $7
 $17
As of December 31, 2017Exelon ComEd PECO BGE PHI Pepco DPL ACE
Purchased receivables$298
 $87
 $70
 $58
 $83
 $56
 $9
 $18
Allowance for uncollectible accounts(a)
(31) (14) (5) (3) (9) (5) (1) (3)
Purchased receivables, net$267
 $73
 $65
 $55
 $74
 $51
 $8
 $15
_________
(a)For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing tariff.

7. Impairment of Long-Lived Assets (Exelon and Generation)
Registrants evaluate long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In the second quarter of 2018, updates to Exelon's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than its carrying value. The fair value analysis wasis 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. Changes in those inputs could potentially result in material future impairments of the Registrants' long-lived assets.
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to Pacific Gas and Electric Company (PG&E) through a PPA. As of March 31, 2019, Generation had approximately $750 million of net long-lived assets related to Antelope Valley. As a result long-lived merchant wind assets held and used with a net carrying amount of $41 million were fully impaired and a pre-tax impairment charge of $41 million was recorded during the second quarter of 2018 within Operating and maintenance expensePG&E bankruptcy filing in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
During the first quarter of 2018, Mystic unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation announced it had formally notified ISO-NE of the early retirement of its Mystic Generating Station's units 7, 8, 9 and the Mystic Jet unit (Mystic Generating Station assets) absent regulatory reforms. These events suggested that the carrying value of its New England asset group may be impaired. As a result,2019, Generation completed a comprehensive review of theAntelope Valley's estimated undiscounted future cash flows of the New England asset group and no impairment charge was required. Further developmentsrecorded. Significant changes in assumptions such as the failurelikelihood of ISO-NE to adopt interim and long-term solutions for reliability and fuel securitythe PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of the New England asset group,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 million of additional net long-lived assets as of March 31, 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 8 — Early Plant Retirements11 - Debt and Credit Agreements for additional information on the early retirement of the Mystic Generating Station assets.PG&E bankruptcy.
On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate an orderly sales process to sell the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP's assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a pre-tax impairment charge of $460 million within Operating and maintenance expense on their Consolidated Statements of Operations and Comprehensive Income of which $418 million was recorded in the second quarter of 2017. On November 7, 2017, EGTP and its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware and, as a result, Exelon and Generation deconsolidated EGTP's assets and liabilities from their consolidated financial statements. See Note 4 — Mergers, Acquisitions and Dispositions for additional information.

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

8. Early Plant Retirements (Exelon and Generation)
Exelon and Generation continue tocontinuously evaluate factors that affect the current and expected economic value of each of Generation’s plants. Factors that will continue to affect the economic value of Generation’s plants, include,including, but are 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 decommissioning trustNDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(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 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 either 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 nuclear plants could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future results of operations, cash flows and financial positions.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. The plant is currently committed to operate through May 2019auction and is licensed to operate through 2034. Onon 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, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019. TMI is currently committed to operate through May 2019 and is licensed to operate through 2034. Generation has filed the required market and regulatory notifications to 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, 2019, Generation filed the post shutdown decommissioning activities report (PSDAR) with the NRC detailing the plans for TMI after its final shutdown.
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current operating cycle by Octoberand permanently ceased generation operations in September 2018. In 2010, Generation announced that Oyster Creek would retire by the end of 2019 as part of an agreement with the State of New Jersey to avoid significant costs associated with the construction of cooling towers to meet the State’s then new environmental regulations. Since then, like other nuclear sites, Oyster Creek has continued to face rising operating costs amid a historically low wholesale power price environment. The decision to retire Oyster Creek in 2018 at the end of its current operating cycle involved consideration of several factors, including economic and operating efficiencies, and avoids a refueling outage scheduled for the fall of 2018 that would have required advanced purchasing of fuel fabrication and materials beginning in late February 2018. Generation has filed the required market and regulatory notifications to shut down the plant. PJM has subsequently notified Generation that it has not identified any reliability issues and has approved the deactivation of Oyster Creek as proposed.
As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized one-timeincremental non-cash charges in Operatingto 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 expense relatedexpenses. See Note 13 — Nuclear Decommissioning for additional information on changes to materialsthe nuclear decommissioning ARO balance. The total impact for the three months ended March 31, 2019 and supplies inventory2018 are summarized in the table below.
  Three Months Ended
March 31,
Income statement expense (pre-tax) 2019 2018
Depreciation and amortization(a)
    
Accelerated depreciation(b)
 $74
 $137
Accelerated nuclear fuel amortization 5
 15
Operating and maintenance(c)
 (83) 26
Total $(4) $178
_________
(a)Reflects incremental accelerated depreciation and amortization for TMI for the three months ended March 31, 2019. Reflects incremental accelerated depreciation for TMI and Oyster Creek for the three months ended March 31, 2018. The Oyster Creek amounts are from February 2, 2018 through March 31, 2018.
(b)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c)In 2019, primarily reflects decrease to estimated decommissioning costs for TMI. 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.

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

reserve adjustments, employee-related costsGeneration’s Dresden, Byron and CWIP impairments, among other items. In additionBraidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to these one-time charges, annual incremental non-cash chargesan early retirement, in a market that does not currently compensate them for their unique contribution to earnings stemming from shorteninggrid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization2021-2022 planning year resulted in the largest volume of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions were also recorded. See Note 13 — Nuclear Decommissioning for additional information on changes to the nuclear decommissioning ARO balance.
During the three and six months ended June 30, 2018, both Exelon's and Generation's results include a net incremental $173 million and $351 million, respectively, of total pre-tax expense associated with the early retirement decisions for TMI and Oyster Creek, as summarizedcapacity ever not selected in the table below.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.
Income statement expense (pre-tax) Q2 2018 YTD 2018
Depreciation and amortization(a)
    
Accelerated depreciation(b)
 $152
 $289
Accelerated nuclear fuel amortization 19
 34
Operating and maintenance(c)
 2
 28
Total $173
 $351
_________
(a)Reflects incremental accelerated depreciation and amortization for TMI and Oyster Creek for the three and six months ended June 30, 2018. The Oyster Creek year-to-date amounts are from February 2, 2018 through June 30, 2018.
(b)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c)Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.
Exelon's and Generation's 2017 results included a net incremental $339 million of total pre-tax expense associated with the early retirement decision for TMI, as summarized in the table below.
Income statement expense (pre-tax) Q2 2017 Q3 2017 Q4 2017 YTD 2017
Depreciation and amortization(a)
        
Accelerated depreciation(b)
 $35
 $106
 $109
 $250
Accelerated nuclear fuel amortization 2
 6
 4
 12
Operating and maintenance(c)
 71
 5
 1
 77
Total $108
 $117
 $114
 $339
_________
(a)Reflects incremental charges for TMI including incremental accelerated depreciation and amortization from May 30, 2017 through December 31, 2017.
(b)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c)Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.
In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants including Salem, of whichOther Generation owns a 42.59% ownership interest. Although Salem is committed to operate through May 2021, the plant faces continued economic challenges and PSEG, as the operator of the plant, is exploring all options.
On May 23, 2018, the Governor of New Jersey signed new legislation, which became effective immediately, that will establish a ZEC program providing compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the new legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. The NJBPU has 180 days from the effective date to establish procedures for implementation of the ZEC

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

program and 330 days from the effective date to determine which nuclear power plants are selected to receive ZECs under the program. Selected nuclear plants will receive ZEC payments for each energy year (12-month period from June 1 through May 31) within 90 days after the completion of such energy year. Assuming the successful implementation of the New Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk of earlier retirement for Salem. See Note 6 — Regulatory Matters for additional information on the New Jersey ZEC program.
The following table provides the balance sheet amounts as of June 30, 2018 for Generation’s ownership share of the significant assets and liabilities associated with Salem.
  June 30, 2018
Asset Balances  
Materials and supplies inventory $45
Nuclear fuel inventory, net 94
Completed plant, net 611
Construction work in progress 28
Liability Balances  
Asset retirement obligation (451)
   
NRC License Renewal Term 2036 (unit 1)
  2040 (unit 2)
On March 29, 2018, Generation announced it had formally notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets absent regulatory reforms on June 1, 2022, at the end of the current capacity commitment for Mystic unitsUnits 7 and 8. Mystic unitUnit 9 is currently committed through May 2021. Absent any regulatory reforms to properly value reliability and regional fuel security, these units will not participate in the Forward Capacity Auction (FCA) scheduled for February 2019 for the 2022 - 2023 capacity commitment period.
The ISO-NE announced that it would take a three-step approach to fuel security. First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic units 8 and 9 for fuel security for the 2022 - 2024 capacity commitment periods. Second, ISO-NE planned to file tariff revisions to allow it to retain other resources for fuel security in the capacity market if necessary in the future. Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic units 8 and 9, cannot recover future operating costs, including the cost of procuring fuel.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic unitsUnits 8 and 9 for the period between June 1, 2022 - May 31, 2024. Among the costs included in the filing are costs associated with the Distrigas facility. Generation asked that FERC establish an expedited settlement process that would allow Generation to know the outcome of the cost-of-service proceeding prior to making a final decision as to whether to unconditionally retire the plants beginning June 1, 2022. A number of parties filed protests in response to the May 16, 2018 filing.
On July 2, 2018, FERC issued an order denying ISO-NE’s May 1, 2018 waiver request on procedural grounds but accepting ISO-NE’s conclusions that retirement of Mystic units 8 and 9 could cause a

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

violation of mandatory reliability standards as soon as 2022. Accordingly, FERC ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address demonstrated fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. FERC also extended the deadline by which Generation must make a retirement decision for Mystic units 8 and 9 to January 4, 2019. In addition, notwithstanding its denial of the waiver request, FERC stated that it will continue to evaluate Mystic’s May 16, 2018 cost-of-service agreement filing.
On July 13,December 20, 2018, FERC issued an order accepting Generation’s cost-of-servicethe cost of service agreement for filingreflecting a number of adjustments to the annual fixed revenue requirement and making findings on certain issues, including thatallowing for recovery of fuel supplya 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 due on July 18, 2019. On January 4, 2019, Generation notified ISO-NE that it will participate in the Forward Capacity Market auction for the Distrigas facility are not prohibited if they are just and reasonable. Additionally, the order established hearing procedures2022 - 2023 capacity commitment period. In addition, on an expedited schedule. Any settlement discussions are to be undertaken on a parallel track with the hearing.
January 22, 2019, Exelon and Generation cannot predictseveral other parties filed requests for rehearing of certain findings of the final outcomeDecember 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 March 25, 2019, ISO-NE filed the Inventoried Energy Program, which is intended to provide an interim fuel security program pending conclusion of these proceedings or the potential financial impact, if any,stakeholder process to develop a long-term, market-based solution to address fuel security. Exelon filed comments on Exelon or Generation.the Inventoried Energy Program proposal on April 15, 2019. FERC has ordered ISO-NE to file the long-term, market-based fuel security rules by October 15, 2019.
The following table provides the balance sheet amounts as of June 30, 2018March 31, 2019 for Exelon's and Generation’s significant assets and liabilities associated with the Mystic Generating Station assets.Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by a decision to permanently cease generation operations in the absence of long-term market rule changes.
 June 30, 2018 March 31, 2019
Asset Balances    
Materials and supplies inventory $26
 $30
Fuel inventory 19
 22
Completed plant, net 887
 900
Construction work in progress 3
 2
Prepaid expenses(a)
 11
Liability Balances    
Asset retirement obligation (5) (1)
Accrued expenses(a)
 (2)
_________
(a)Reflects ending balances only as they relate to Mystic's Long-term Service Agreement.

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

9. Fair Value of Financial Assets and Liabilities (All Registrants)
Fair Value of Financial Liabilities Recorded at 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 June 30, 2018March 31, 2019 and December 31, 2017:2018:
Exelon
June 30, 2018March 31, 2019
Carrying
Amount
 Fair Value
Carrying
Amount
 Fair Value
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Short-term liabilities(a)
$1,252
 $—
 $1,252
 $—
 $1,252
$1,254
 $—
 $1,254
 $—
 $1,254
Long-term debt (including amounts due within one year)(c)(a)
34,337
 —
 32,388
 2,154
 34,542
35,468
 —
 35,066
 2,188
 37,254
Long-term debt to financing trusts(d)(b)
389
 —
 —
 420
 420
390
 —
 —
 411
 411
SNF obligation1,157
 —
 921
 —
 921
1,178
 —
 989
 —
 989
December 31, 2017December 31, 2018
Carrying
Amount
 Fair Value
Carrying
Amount
 Fair Value
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Short-term liabilities(a)
$929
 $—
 $929
 $—
 $929
$714
 $—
 $714
 $—
 $714
Long-term debt (including amounts due within one year)(c)(a)
34,264
 —
 34,735
 1,970
 36,705
35,424
 —
 33,711
 2,158
 35,869
Long-term debt to financing trusts(d)(b)
389
 —
 —
 431
 431
390
 —
 —
 400
 400
SNF obligation1,147
 —
 936
 —
 936
1,171
 —
 949
 —
 949
Generation
June 30, 2018March 31, 2019
Carrying
Amount
 Fair Value
Carrying
Amount
 Fair Value
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(c)(a)
$8,886
 $—
 $7,461
 $1,532
 $8,993
$8,747
 $—
 $7,641
 $1,443
 $9,084
SNF obligation1,157
 —
 921
 —
 921
1,178
 —
 989
 —
 989
 December 31, 2017
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$2
 $—
 $2
 $—
 $2
Long-term debt (including amounts due within one year)(b)(c)
8,990
 —
 7,839
 1,673
 9,512
SNF obligation1,147
 —
 936
 —
 936
 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)

ComEd
June 30, 2018March 31, 2019
Carrying
Amount
 Fair Value
Carrying
Amount
 Fair Value
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Short-term liabilities(a)
$320
 $—
 $320
 $—
 $320
$322
 $—
 $322
 $—
 $322
Long-term debt (including amounts due within one year)(c)(a)
7,695
 —
 7,865
 —
 7,865
8,194
 —
 8,855
 —
 8,855
Long-term debt to financing trusts(d)(b)
205
 —
 —
 219
 219
205
 —
 —
 215
 215
December 31, 2017December 31, 2018
Carrying
Amount
 Fair Value
Carrying
Amount
 Fair Value
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(c)(a)
$7,601
 $—
 $8,418
 $—
 $8,418
$8,101
 $—
 $8,390
 $—
 $8,390
Long-term debt to financing trusts(d)(b)
205
 —
 —
 227
 227
205
 —
 —
 209
 209
PECO
 June 30, 2018
 
Carrying
Amount
 Fair Value
 Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$50
 $—
 $50
 $—
 $50
Long-term debt (including amounts due within one year)(b)(c)
2,773
 —
 2,819
 50
 2,869
Long-term debt to financing trusts(d)
184
 —
 —
 201
 201
 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, 2017December 31, 2018
Carrying
Amount
 Fair Value
Carrying
Amount
 Fair Value
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(c)(a)
$2,903
 $—
 $3,194
 $—
 $3,194
$3,084
 $—
 $3,157
 $50
 $3,207
Long-term debt to financing trusts(d)(b)
184
 —
 —
 204
 204
184
 —
 —
 191
 191
BGE
June 30, 2018March 31, 2019
Carrying
Amount
 Fair Value
Carrying
Amount
 Fair Value
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Short-term liabilities(a)
$136
 $—
 $136
 $—
 $136
$106
 $—
 $106
 $—
 $106
Long-term debt (including amounts due within one year)(c)(a)
2,578
 —
 2,629
 —
 2,629
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, 2017December 31, 2018
Carrying
Amount
 Fair Value
Carrying
Amount
 Fair Value
Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total
Short-term liabilities(a)
$77
 $—
 $77
 $—
 $77
$35
 $—
 $35
 $—
 $35
Long-term debt (including amounts due within one year)(c)(a)
2,577
 —
 2,825
 —
 2,825
2,876
 —
 2,950
 —
 2,950
PHI
June 30, 2018March 31, 2019
Carrying Amount Fair ValueCarrying Amount Fair Value
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$247
 $—
 $247
 $—
 $247
$326
 $—
 $326
 $—
 $326
Long-term debt (including amounts due within one year)(c)(a)
6,116
 —
 5,300
 572
 5,872
6,244
 —
 5,608
 695
 6,303
December 31, 2017December 31, 2018
Carrying Amount Fair ValueCarrying Amount Fair Value
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$350
 $—
 $350
 $—
 $350
$179
 $—
 $179
 $—
 $179
Long-term debt (including amounts due within one year)(c)(a)
5,874
 —
 5,722
 297
 6,019
6,259
 —
 5,436
 665
 6,101
Pepco
 June 30, 2018
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(b)(c)
$2,631
 $—
 $2,863
 $107
 $2,970
 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, 2017December 31, 2018
Carrying Amount Fair ValueCarrying Amount Fair Value
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$26
 $—
 $26
 $—
 $26
$40
 $—
 $40
 $—
 $40
Long-term debt (including amounts due within one year)(c)(a)
2,540
 —
 3,114
 9
 3,123
2,719
 —
 2,901
 196
 3,097
DPL
 June 30, 2018
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)(b)(c)
$1,494
 $—
 $1,295
 $196
 $1,491
 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, 2017
 Carrying Amount Fair Value
  Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$216
 $—
 $216
 $—
 $216
Long-term debt (including amounts due within one year)(b)(c)
1,300
 —
 1,393
 —
 1,393
 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
June 30, 2018March 31, 2019
Carrying Amount Fair ValueCarrying Amount Fair Value
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$247
 $—
 $247
 $—
 $247
$216
 $—
 $216
 $—
 $216
Long-term debt (including amounts due within one year)(c)(a)
1,107
 —
 898
 269
 1,167
1,184
 —
 1,004
 283
 1,287
December 31, 2017December 31, 2018
Carrying Amount Fair ValueCarrying Amount Fair Value
 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Short-term liabilities(a)
$108
 $—
 $108
 $—
 $108
$139
 $—
 $139
 $—
 $139
Long-term debt (including amounts due within one year)(c)(a)
1,121
 —
 949
 288
 1,237
1,188
 —
 987
 275
 1,262
_________
(a)Level 1 securities consist of dividends payable (included in other current liabilities). Level 2 securities consist of short term borrowings.
(b)Includes unamortized debt issuance costs which are not fair valued of $213$216 million, $55$49 million, $59$67 million, $20$22 million, $16$18 million, $12$14 million, $35$33 million, $12 million and $4$6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of June 30, 2018.March 31, 2019. Includes unamortized debt issuance costs which are not fair valued of $201$216 million, $60$51 million, $52$63 million, $17$23 million, $17$18 million, $6$14 million, $32$34 million, $11$12 million and $5$7 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of December 31, 2017.2018.
(c)Level 2 securities consist of fixed-rate taxable debt securities, fixed-rate tax-exempt debt, variable rate tax-exempt debt and variable rate non-recourse debt. Level 3 securities consist of fixed-rate private placement taxable debt securities, fixed rate nonrecourse debt, government-backed fixed rate non-recourse debt and loan agreements.
(d)(b)Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of June 30, 2018March 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, 2017.2018.
Recurring Fair Value Measurements
Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
Transfers in and out of levels are recognized as of the end of the reporting period when the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Additionally, there

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

were no material transfers between Level 1 and Level 2 during the six months ended June 30, 2018 for cash equivalents, nuclear decommissioning trust fund investments, Pledged assets for Zion Station decommissioning, Rabbi trust investments, and Deferred compensation obligations. For derivative contracts, transfers into Level 2 from Level 3 generally occur when the contract tenor becomes more observable and due to changes in market liquidity or assumptions for certain commodity contracts.
Generation and Exelon
In accordance with the applicable guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a practical expedient are no longer classified within the fair value hierarchy and are included under "Not subject to leveling" in the table below.
The following tables present assets and liabilities measured and recorded at fair value onin Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2018March 31, 2019 and December 31, 2017:
 Generation Exelon
As of June 30, 2018Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
Assets                   
Cash equivalents(a)
$301
 $—
 $—
 $—
 $301
 $660
 $—
 $—
 $—
 $660
NDT fund investments        
         
Cash equivalents(b)
212
 94
 —
 —
 306
 212
 94
 —
 —
 306
Equities3,429
 1,174
 —

1,948
 6,551
 3,429
 1,174
 —

1,948
 6,551
Fixed income                   
Corporate debt—
 1,593
 231
 —
 1,824
 —
 1,593
 231
 —
 1,824
U.S. Treasury and agencies2,007
 94
 —
 —
 2,101
 2,007
 94
 —
 —
 2,101
Foreign governments—
 61
 —
 —
 61
 —
 61
 —
 —
 61
State and municipal debt—
 236
 —
 —
 236
 —
 236
 —
 —
 236
Other(c)
—
 33
 —
 908
 941
 —
 33
 —
 908
 941
Fixed income subtotal2,007

2,017

231
 908

5,163

2,007

2,017

231
 908

5,163
Middle market lending—
 —
 354
 216
 570
 —
 —
 354
 216
 570
Private equity—
 —
 —
 270
 270
 —
 —
 —
 270
 270
Real estate—
 —
 —
 506
 506
 —
 —
 —
 506
 506
NDT fund investments subtotal(d)
5,648

3,285

585
 3,848

13,366

5,648

3,285

585
 3,848

13,366
Pledged assets for Zion Station decommissioning                   
Cash equivalents3
 —
 —
 —
 3
 3
 —
 —
 —
 3
Middle market lending—
 —
 18
 —
 18
 —
 —
 18
 —
 18
Pledged assets for Zion Station
decommissioning subtotal(e)
3

—

18
 —

21

3

—

18
 —

21
2018:

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

Generation ExelonGeneration Exelon
As of June 30, 2018Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
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
Fixed income subtotal2,033

1,836

236
 936

5,041

2,033

1,836

236
 936

5,041
Middle market lending—
 —
 303
 406
 709
 —
 —
 303
 406
 709
Private equity—
 —
 —
 352
 352
 —
 —
 —
 352
 352
Real estate—
 —
 —
 535
 535
 —
 —
 —
 535
 535
NDT fund investments subtotal(d)
5,462

3,663

540
 3,774

13,439

5,462

3,663

540
 3,774

13,439
Rabbi trust investments        
         
        
         
Cash equivalents(a)5
 —
 —
 —
 5
 45
 —
 —
 —
 45
Cash equivalents4
 —
 —
 —
 4
 47
 —
 —
 —
 47
Mutual funds24
 —
 —
 —
 24
 73
 —
 —
 —
 73
25
 —
 —
 —
 25
 74
 —
 —
 —
 74
Fixed income—
 —
 —
 —
 —
 —
 18
 —
 —
 18
—
 —
 —
 —
 —
 —
 14
 —
 —
 14
Life insurance contracts—
 22
 —
 —
 22
 —
 71
 36
 —
 107
—
 23
 —
 —
 23
 —
 71
 39
 —
 110
Rabbi trust investments subtotal(f)
29

22

—
 —

51

118

89

36
 —

243
Rabbi trust investments subtotal(e)
29

23

—
 —

52

121

85

39
 —

245
Commodity derivative assets                                      
Economic hedges237
 2,091
 1,770
 —
 4,098
 237
 2,091
 1,770
 —
 4,098
273
 2,164
 1,442
 —
 3,879
 273
 2,164
 1,442
 —
 3,879
Proprietary trading—
 138
 83
 —
 221
 —
 138
 83
 —
 221
—
 74
 104
 —
 178
 —
 74
 104
 —
 178
Effect of netting and allocation of collateral(g) (h)
(219) (1,912) (950) —
 (3,081) (219) (1,912) (950) —
 (3,081)
Effect of netting and allocation of collateral(f)(g)
(294) (1,836) (820) —
 (2,950) (294) (1,836) (820) —
 (2,950)
Commodity derivative assets subtotal18

317

903
 —

1,238

18

317

903
 —

1,238
(21)
402

726
 —

1,107

(21)
402

726
 —

1,107
Interest rate and foreign currency derivative assets                                      
Derivatives designated as hedging instruments—
 16
 —
 —
 16
 —
 16
 —
 —
 16
Economic hedges—
 6
 —
 —
 6
 —
 6
 —
 —
 6
—
 4
 —
 —
 4
 —
 4
 —
 —
 4
Effect of netting and allocation of collateral—
 (4) —
 —
 (4) —
 (4) —
 —
 (4)—
 (5) —
 —
 (5) —
 (5) —
 —
 (5)
Interest rate and foreign currency derivative assets subtotal—

18

—
 —

18

—

18

—
 —

18
—

(1)
—
 —

(1)
—

(1)
—
 —

(1)
Other investments—
 —
 36
 —
 36
 —
 —
 36
 —
 36
—
 —
 42
 —
 42
 —
 —
 42
 —
 42
Total assets5,999

3,642

1,542

3,848

15,031

6,447

3,709

1,578

3,848

15,582
5,840

4,087

1,308

3,774

15,009

6,379

4,149

1,347

3,774

15,649
Liabilities                   
Commodity derivative liabilities                   
Economic hedges(329) (2,244) (1,234) —
 (3,807) (329) (2,244) (1,486) —
 (4,059)
Proprietary trading—
 (152) (20) —
 (172) —
 (152) (20) —
 (172)
Effect of netting and allocation of collateral(g) (h)
255
 2,120
 1,088
 —
 3,463
 255
 2,120
 1,088
 —
 3,463
Commodity derivative liabilities subtotal(74) (276) (166) —
 (516) (74) (276) (418) —
 (768)
Interest rate and foreign currency derivative liabilities                   
Derivatives designated as hedging instruments—
 —
 —
 —
 —
 —
 (8) —
 —
 (8)
Economic hedges—
 (3) —
 —
 (3) —
 (3) —
 —
 (3)
Effect of netting and allocation of collateral—
 4
 —
 —
 4
 —
 4
 —
 —
 4
Interest rate and foreign currency derivative liabilities subtotal—

1

—
 —

1

—

(7)
—
 —

(7)
Deferred compensation obligation—
 (34) —
 —
 (34) —
 (136) —
 —
 (136)
Total liabilities(74)
(309)
(166) —

(549)
(74)
(419)
(418) —

(911)
Total net assets$5,925

$3,333

$1,376
 $3,848

$14,482

$6,373

$3,290

$1,160
 $3,848

$14,671

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

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

Cash equivalents(b)
135
 85
 —
 —
 220
 135
 85
 —
 —
 220
Equities4,163

915

—

2,176

7,254

4,163

915

—

2,176

7,254
Fixed income                   
Corporate debt—
 1,614
 251
 —
 1,865
 —
 1,614
 251
 —
 1,865
U.S. Treasury and agencies1,917
 52
 —
 —
 1,969
 1,917
 52
 —
 —
 1,969
Foreign governments—
 82
 —
 —
 82
 —
 82
 —
 —
 82
State and municipal debt—
 263
 —
 —
 263
 —
 263
 —
 —
 263
Other(c)
—
 47
 —
 510
 557
 —
 47
 —
 510
 557
Fixed income subtotal1,917

2,058

251
 510

4,736

1,917

2,058

251
 510

4,736
Middle market lending—
 —
 397
 131
 528
 —
 —
 397
 131
 528
Private equity—
 —
 —
 222
 222
 —
 —
 —
 222
 222
Real estate—
 —
 —
 471
 471
 —
 —
 —
 471
 471
NDT fund investments subtotal(d)
6,215

3,058

648
 3,510

13,431

6,215

3,058

648
 3,510
 13,431
Pledged assets for Zion Station decommissioning                   
Cash equivalents2
 —
 —
 —
 2
 2
 —
 —
 —
 2
Equities—
 1
 —
 —
 1
 —
 1
 —
 —
 1
Middle market lending—
 —
 12
 24
 36
 —
 —
 12
 24
 36
Pledged assets for Zion Station decommissioning subtotal(e)
2

1

12
 24

39

2

1

12
 24

39
Rabbi trust investments                   
Cash equivalents5
 —
 —
 —
 5
 77
 —
 —
 —
 77
Mutual funds23
 —
 —
 —
 23
 58
 —
 —
 —
 58
Fixed income—
 —
 —
 —
 —
 —
 12
 —
 —
 12
Life insurance contracts—
 22
 —
 —
 22
 —
 71
 22
 —
 93
Rabbi trust investments subtotal(f)
28

22

—
 —

50

135

83

22
 —

240
Commodity derivative assets                   
Economic hedges557
 2,378
 1,290
 —
 4,225
 557
 2,378
 1,290
 —
 4,225
Proprietary trading2
 31
 35
 —
 68
 2
 31
 35
 —
 68
Effect of netting and allocation of collateral(g) (h)
(585) (1,769) (635) —
 (2,989) (585) (1,769) (635) —
 (2,989)
Commodity derivative assets subtotal(26)
640

690
 —

1,304

(26)
640

690
 —

1,304
 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

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

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

         

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

—
 —

6

(2)
11

—
 —

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

3,729

1,387
 3,534

15,035

6,980

3,793

1,409
 3,534

15,716
Liabilities        
         
Commodity derivative liabilities                   
Economic hedges(712) (2,226) (845) —
 (3,783) (713) (2,226) (1,101) —
 (4,040)
Proprietary trading(2) (42) (9) —
 (53) (2) (42) (9) —
 (53)
Effect of netting and allocation of collateral(g) (h)
650
 2,089
 716
 —
 3,455
 651
 2,089
 716
 —
 3,456
Commodity derivative liabilities subtotal(64)
(179)
(138) —

(381)
(64)
(179)
(394) —

(637)
Interest rate and foreign currency derivative liabilities                   
Derivatives designated as hedging instruments—
 (2) —
 —
 (2) —
 (2) —
 —
 (2)
Economic hedges(1) (8) —
 —
 (9) (1) (8) —
 —
 (9)
Effect of netting and allocation of collateral2
 5
 —
 —
 7
 2
 5
 —
 —
 7
Interest rate and foreign currency derivative liabilities subtotal1

(5)
—
 —

(4)
1

(5)
—
 —

(4)
Deferred compensation obligation—
 (38) —
 —
 (38) —
 (145) —
 —
 (145)
Total liabilities(63)
(222)
(138) —

(423)
(63)
(329)
(394) —

(786)
Total net assets$6,322

$3,507

$1,249
 $3,534

$14,612

$6,917

$3,464

$1,015
 $3,534

$14,930
 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 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
Liabilities        
         
Commodity derivative liabilities                   
Economic hedges(642) (2,963) (1,027) —
 (4,632) (642) (2,963) (1,276) —
 (4,881)
Proprietary trading—
 (73) (21) —
 (94) —
 (73) (21) —
 (94)
Effect of netting and allocation of collateral(f)(g)
639
 2,581
 808
 —
 4,028
 639
 2,581
 808
 —
 4,028
Commodity derivative liabilities subtotal(3)
(455)
(240) —

(698)
(3)
(455)
(489) —

(947)
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)
Total liabilities(3)
(493)
(240) —

(736)
(3)
(599)
(489) —

(1,091)
Total net assets$5,817

$3,609

$1,160
 $3,433

$14,019

$6,570

$3,566

$949
 $3,433

$14,518
_________
(a)Generation excludes cash of $204$270 million and $259$283 million at June 30, 2018March 31, 2019 and December 31, 20172018 and restricted cash of $45$36 million and $127$39 million at June 30, 2018March 31, 2019 and December 31, 2017.2018.  Exelon excludes cash of $296$426 million and $389$458 million at June 30, 2018March 31, 2019 and December 31, 20172018 and restricted cash of $72$71 million and $145$80 million at June 30, 2018March 31, 2019 and December 31, 20172018 and includes long-term restricted cash of $128$211 million and $85$185 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, which is reported in Other deferred debits onin the Consolidated Balance Sheets.
(b)Includes $48$43 million and $77$50 million of cash received from outstanding repurchase agreements at June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.
(c)Includes derivative instruments of less than $1$7 million and less than $1$44 million, which have a total notional amount of $965$1,223 million and $811$1,432 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, 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 $103$94 million and $82$130 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, 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)Excludes net assets of less than $1 million at June 30, 2018. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
(f)The amount of unrealized gains/(losses) at Generation totaled less than $1 million for the three months ended March 31, 2019 and less thanMarch 31, 2018, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million for the three months ended June 30,March 31, 2019 and March 31, 2018, and June 30, 2017, respectively. The amount of unrealized gains/(losses) at Generation totaled less than $1

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

million and $1 million for the six months ended June 30, 2018 and June 30, 2017, respectively. The amount of unrealized gains/(losses) at Exelon totaled less than $1 million and $1 million for the three months ended June 30, 2018 and June 30, 2017, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million and $3 million for the six months ended June 30, 2018 and June 30, 2017, respectively.
(g)(f)Collateral posted/(received) from counterparties totaled $36$52 million, $208$283 million and $138$157 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, 2018.March 31, 2019. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $65$57 million, $320$224 million and $81$76 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2017.2018.
(h)(g)Of the collateral posted/(received), $11$(33) million and $(94) million represents variation margin on the exchanges as of June 30, 2018. Of the collateral posted/(received), $(117) million represents variation margin on the exchanges as ofMarch 31, 2019 and December 31, 2017.2018, respectively.
Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $68$71 million as of June 30, 2018.March 31, 2019. Changes were immaterial in fair value, cumulative adjustments and impairments for the three and six months ended June 30, 2018.
ComEd, PECO and BGE
The following tables present assets and liabilities measured and recorded at fair value on ComEd's, PECO's and BGE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2018 and DecemberMarch 31, 2017:
 ComEd PECO BGE
As of June 30, 2018Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets                       
Cash equivalents(a)
$113
 $—
 $—
 $113
 $5
 $—
 $—
 $5
 $—
 $—
 $—
 $—
Rabbi trust investments      
       
       
Cash equivalents—
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Mutual funds—
 —
 —
 —
 7
 —
 —
 7
 6
 —
 —
 6
Life insurance contracts—
 ���
 —
 —
 —
 10
 —
 10
 —
 —
 —
 —
Rabbi trust investments subtotal(b)
—

—

—

—

7

10

—

17

6

—

—

6
Total assets113

—

—

113

12

10

—

22

6

—

—

6
Liabilities      
       
       
Deferred compensation obligation—
 (7) —
 (7) —
 (9) —
 (9) —
 (4) —
 (4)
Mark-to-market derivative liabilities(c)
—
 —
 (252) (252) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (7) (252) (259) —
 (9) —
 (9) —
 (4) —
 (4)
Total net assets (liabilities)$113
 $(7) $(252) $(146) $12
 $1
 $—
 $13
 $6
 $(4) $—
 $2
2019.

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

ComEd, PECO and BGE
The following tables present assets and liabilities measured and recorded at fair value in ComEd's, PECO's and BGE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2019 and December 31, 2018:
ComEd PECO BGEComEd PECO BGE
As of December 31, 2017Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
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)
$98
 $—
 $—
 $98
 $228
 $—
 $—
 $228
 $—
 $—
 $—
 $—
$194
 $—
 $—
 $194
 $16
 $—
 $—
 $16
 $3
 $—
 $—
 $3
Rabbi trust investments      
       
       
      
       
       
Mutual funds—
 —
 —
 —
 7
 —
 —
 7
 6
 —
 —
 6
—
 —
 —
 —
 7
 —
 —
 7
 6
 —
 —
 6
Life insurance contracts—
 —
 —
 —
 —
 10
 —
 10
 —
 —
 —
 —
—
 —
 —
 —
 —
 10
 —
 10
 —
 —
 —
 —
Rabbi trust investments subtotal(b)
—

—

—

—

7

10

—

17

6

—

—

6
—

—

—

—

7

10

—

17

6

—

—

6
Total assets98

—

—

98

235

10

—

245

6

—

—

6
194

—

—

194

23

10

—

33

9

—

—

9
Liabilities      
       
       
      
       
       
Deferred compensation obligation—
 (8) —
 (8) —
 (11) —
 (11) —
 (5) —
 (5)—
 (7) —
 (7) —
 (10) —
 (10) —
 (5) —
 (5)
Mark-to-market derivative liabilities(c)
—
 —
 (256) (256) —
 —
 —
 —
 —
 —
 —
 —
—
 —
 (240) (240) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (8) (256) (264) —
 (11) —
 (11) —
 (5) —
 (5)—
 (7) (240) (247) —
 (10) —
 (10) —
 (5) —
 (5)
Total net assets (liabilities)$98
 $(8) $(256) $(166) $235
 $(1) $—
 $234
 $6
 $(5) $—
 $1
$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 $30$69 million and $45$93 million at June 30, 2018March 31, 2019 and December 31, 20172018 and restricted cash of $15 million and $28 million at March 31, 2019 and December 31, 2018 and includes long-term restricted cash of $108$193 million and $62$166 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, which is reported in Other deferred debits onin the Consolidated Balance Sheets.  PECO excludes cash of $18$31 million and $47$24 million at June 30, 2018March 31, 2019 and December 31, 2017.2018.  BGE excludes cash of $12 million and $7 million and $17 million at June 30, 2018March 31, 2019 and December 31, 20172018 and restricted cash of $1 million and $1$2 million at June 30, 2018March 31, 2019 and December 31, 2017.2018.
(b)The amount of unrealized gains/(losses) at ComEd, PECO and BGE totaled less than $1 million for the three and six months ended June 30, 2018March 31, 2019 and June 30, 2017, respectively.March 31, 2018.
(c)The Level 3 balance consists of the current and noncurrent liability of $23$27 million and $229$213 million, respectively, at June 30, 2018,March 31, 2019, and $21$26 million and $235$223 million, respectively, at December 31, 2017,2018, 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 onin 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 June 30, 2018March 31, 2019 and December 31, 2017:2018:
  
As of June 30, 2018 As of December 31, 2017As of March 31, 2019 As of December 31, 2018
PHILevel 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 TotalLevel 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets                              
Cash equivalents(a)
$235
 $—
 $—
 $235
 $83
 $—
 $—
 $83
$63
 $—
 $—
 $63
 $147
 $—
 $—
 $147
Rabbi trust investments      
       
      
       
Cash equivalents39
 —
 —
 39
 72
 —
 —
 72
42
 —
 —
 42
 42
 —
 —
 42
Mutual funds15
 —
 —
 15
 —
 —
 —
 —
14
 —
 —
 14
 13
 —
 —
 13
Fixed income—
 18
 —
 18
 —
 12
 —
 12
—
 14
 —
 14
 —
 15
 —
 15
Life insurance contracts—
 23
 36
 59
 —
 23
 22
 45
—
 22
 39
 61
 —
 22
 38
 60
Rabbi trust investments subtotal(b)
54

41

36

131

72

35

22

129
56

36

39

131

55

37

38

130
Total assets289

41

36

366
 155

35

22

212
119

36

39

194
 202

37

38

277
Liabilities      
       
      
       
Deferred compensation obligation—
 (22) —
 (22) —
 (25) —
 (25)—
 (20) —
 (20) —
 (21) —
 (21)
Mark-to-market derivative liabilities(c)
—
 —
 —
 —
 (1) —
 —
 (1)
Effect of netting and allocation of collateral—
 —
 —
 —
 1
 —
 —
 1
Mark-to-market derivative liabilities subtotal—

—

—

—

—

—

—

—
Total liabilities—

(22)
—

(22)
—

(25)
—

(25)—

(20)
—

(20)
—

(21)
—

(21)
Total net assets$289

$19

$36

$344
 $155

$10

$22

$187
$119

$16

$39

$174
 $202

$16

$38

$256
Pepco DPL ACEPepco DPL ACE
As of June 30, 2018Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
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)
$73
 $—
 $—
 $73
 $137
 $—
 $—
 $137
 $25
 $—
 $—
 $25
$35
 $—
 $—
 $35
 $2
 $—
 $—
 $2
 $21
 $—
 $—
 $21
Rabbi trust investments                                              
Cash equivalents38
 —
 —
 38
 —
 —
 —
 —
 —
 —
 —
 —
42
 —
 —
 42
 —
 —
 —
 —
 —
 —
 —
 —
Fixed income—
 7
 —
 7
 —
 —
 —
 —
 —
 —
 —
 —
—
 4
 —
 4
 —
 —
 —
 —
 —
 —
 —
 —
Life insurance contracts—
 23
 36
 59
 —
 —
 —
 —
 —
 —
 —
 —
—
 22
 38
 60
 —
 —
 —
 —
 —
 —
 —
 —
Rabbi trust investments subtotal(b)
38

30

36

104

—

—

—

—

—

—

—

—
42

26

38

106

—

—

—

—

—

—

—

—
Total assets111

30

36

177

137

—

—

137

25

—

—

25
77

26

38

141

2

—

—

2

21

—

—

21
Liabilities
 
 
 

 
 
 
 
 
 
 
 

 
 
 

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

(4)
—

(4)
—

(1)
—

(1)
—

—

—

—
—

(3)
—

(3)
—

(1)
—

(1)
—

—

—

—
Total net assets (liabilities)$111
 $26
 $36
 $173
 $137
 $(1) $—
 $136
 $25
 $—
 $—
 $25
$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 ACEPepco DPL ACE
As of December 31, 2017Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
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)
$36
 $—
 $—
 $36
 $—
 $—
 $—
 $—
 $29
 $—
 $—
 $29
$38
 $—
 $—
 $38
 $16
 $—
 $—
 $16
 $23
 $—
 $—
 $23
Rabbi trust investments                                              
Cash equivalents44
 —
 —
 44
 —
 —
 —
 —
 —
 —
 —
 —
41
 —
 —
 41
 —
 —
 —
 —
 —
 —
 —
 —
Fixed income—
 12
 —
 12
 —
 —
 —
 —
 —
 —
 —
 —
—
 5
 —
 5
 —
 —
 —
 —
 —
 —
 —
 —
Life insurance contracts—
 23
 22
 45
 —
 —
 —
 —
 —
 —
 —
 —
—
 22
 37
 59
 —
 —
 —
 —
 —
 —
 —
 —
Rabbi trust investments subtotal(b)
44

35

22

101

—

—

—

—

—

—

—

—
41

27

37

105

—

—

—

—

—

—

—

—
Total assets80

35

22

137

—

—

—

—

29

—

—

29
79

27

37

143

16

—

—

16

23

—

—

23
Liabilities                                              
Deferred compensation obligation—
 (4) —
 (4) —
 (1) —
 (1) —
 —
 —
 —
—
 (3) —
 (3) —
 (1) —
 (1) —
 —
 —
 —
Mark-to-market derivative liabilities(c)
—
 —
 —
 —
 (1) —
 —
 (1) —
 —
 —
 —
Effect of netting and allocation of collateral—
 —
 —
 —
 1
 —
 —
 1
 —
 —
 —
 —
Mark-to-market derivative liabilities subtotal—
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (4) —
 (4) —
 (1) —
 (1) —
 —
 —
 —
—
 (3) —
 (3) —
 (1) —
 (1) —
 —
 —
 —
Total net assets (liabilities)$80
 $31
 $22

$133
 $—
 $(1) $—
 $(1) $29
 $—
 $—
 $29
$79
 $24
 $37

$140
 $16
 $(1) $—
 $15
 $23
 $—
 $—
 $23
_________
(a)PHI excludes cash of $18$29 million and $12$39 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively, and includes long-term restricted cash of $20 million and $23$19 million at June 30, 2018both March 31, 2019 and December 31, 2017, respectively,2018, which is reported in Other deferred debits onin the Consolidated Balance Sheets.  Pepco excludes cash of $7$11 million and $4$15 million at June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively. DPL excludes cash of $4 million and $2 million at June 30, 2018 and December 31, 2017, respectively. ACE excludes cash of $6 million and $2$8 million at June 30, 2018March 31, 2019 and December 31, 2017, respectively,2018, respectively. ACE excludes cash of $7 million at both March 31, 2019 and December 31, 2018, and includes long-term restricted cash of $20 million and $23$19 million at June 30, 2018both March 31, 2019 and December 31, 2017, respectively,2018, which is reported in Other deferred debits onin the Consolidated Balance Sheets.
(b)The amount of unrealized gains/(losses) at PHI and Pepco totaled $1 million and less than $1 million for both the three and six months ended June 30, 2018March 31, 2019 and June 30, 2017, respectively.2018. The amount of unrealized gains/(losses) at DPL and ACEPepco totaled less than $1 million for the three and six months ended June 30, 2018 and June 30, 2017, respectively.
(c)Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2018 and 2017:

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

 Generation ComEd PHI   Exelon
Three Months Ended June 30, 2018
NDT Fund
Investments
 
Pledged Assets
for Zion Station
Decommissioning
 
Mark-to-Market
Derivatives
 
Other
Investments
 Total Generation 
Mark-to-Market
Derivatives
 
Life Insurance Contracts(c)
 Eliminated in Consolidation Total
Balance as of March 31, 2018$609
 $16
 $918
 $36
 $1,579
 $(267) $23
 $—
 $1,335
Total realized / unrealized gains (losses)        
       
Included in net income—
 —
 (113)
(a) 
—
 (113) —
 1
 —
 (112)
Included in noncurrent payables to affiliates(3) —
 —
 —
 (3) —
 —
 3
 —
Included in payable for Zion Station decommissioning—
 2
 —
 —
 2
 —
 —
 —
 2
Included in regulatory assets/liabilities—
 —
 —
 —
 —
 15
(b) 
—
 (3) 12
Change in collateral—
 —
 (49) —
 (49) —
 —
 —
 (49)
Purchases, sales, issuances and settlements        
       

Purchases17
 —
 13
 —
 30
 —
 —
 —
 30
Sales—
 —
 (1) —
 (1) —
 —
 —
 (1)
Settlements(38) —
 —
 —
 (38) —
 12
(d) 
—
 (26)
Transfers into Level 3—
 —
 (15) —
 (15) —
 —
 —
 (15)
Transfers out of Level 3—
 —
 (16) —
 (16) —
 —
 —
 (16)
Balance at June 30, 2018$585
 $18
 $737
 $36
 $1,376
 $(252) $36
 $—
 $1,160
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2018$(4) $—
 $7
 $—
 $3
 $—
 $—
 $—
 $3

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

 Generation ComEd PHI   Exelon
Six Months Ended June 30, 2018
NDT Fund
Investments
 
Pledged Assets
for Zion Station
Decommissioning
 
Mark-to-Market
Derivatives
 Other Investments Total Generation 
Mark-to-Market
Derivatives
 
Life Insurance Contracts(c)
 Eliminated in Consolidation 
Mark-to-Market
Derivatives
Balance as of December 31, 2017$648
 $12
 $552
 $37
 $1,249
 $(256) $22
 $—
 $1,015
Total realized / unrealized gains (losses)        

       

Included in net income1
 —
 71
(a) 
1
 73
 —
 2
 —
 75
Included in noncurrent payables to affiliates3
 —
 —
 —
 3
 —
 —
 (3) —
Included in payable for Zion Station decommissioning—
 5
 —
 —
 5
 —
 —
 —
 5
Included in regulatory assets—
 —
 —
 —
 —
 4
(b) 
—
 3
 7
Change in collateral—
 —
 57
 —
 57
 —
 —
 —
 57
Purchases, sales, issuances and settlements        

       

Purchases19
 1
 100
 —
 120
 —
 —
 —
 120
Sales—
 —
 (4) —
 (4) —
 —
 —
 (4)
Settlements(86) —
 —
 —
 (86) —
 12
(d) 
—
 (74)
Transfers into Level 3—
 —
 (23) —
 (23) —
 —
 —
 (23)
Transfers out of Level 3—
 —
 (16) (2) (18) —
 —
 —
 (18)
Balance as of June 30, 2018$585
 $18

$737
 $36
 $1,376
 $(252) $36
 $—
 $1,160
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2018$(4) $—
 $263
 $1
 $260
 $—
 $—
 $—
 $260
__________
(a)Includes a reduction for the reclassification of $120 million and $192 million of realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2018, respectively.
(b)Includes $11 million of increases 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 forboth the three months ended June 30,March 31, 2019 and 2018. Includes $6 million of decreases in fair value and an increase for realized losses due to settlements of $10 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2018.
(c)The amounts represented are life insurance contracts at Pepco.
(d)The settlement amount represents the full payment of a loan held against one of Pepco's life insurance policy contracts.

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   ExelonGeneration ComEd PHI   Exelon
Three Months Ended June 30, 2017
NDT Fund
Investments
 
Pledged Assets
for Zion Station
Decommissioning
 
Mark-to-Market
Derivatives
 
Other
Investments
 Total Generation 
Mark-to-Market
Derivatives
 
Life Insurance Contracts(c)
 Eliminated in Consolidation Total
Balance as of March 31, 2017$683
 $20
 $565
 $40
 $1,308
 $(282) $20
 $—
 $1,046
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 income1
 —
 (3)
(a) 
—
 (2) —
 —
 —
 (2)2
 (231)
(a) 
—
 (229) —
 1
 —
 (228)
Included in noncurrent payables to affiliates4
 —
 —
 —
 4
 —
 —
 (4) —
11
 —
 —
 11
 —
 —
 (11) —
Included in payable for Zion Station decommissioning—
 1
 —
 —
 1
 —
 —
 —
 1
Included in regulatory assets—
 —
 —
 —
 —
 26
(b) 
—
 4
 30
Included in regulatory assets/liabilities—
 —
 —
 —
 9
(b) 
—
 11
 20
Change in collateral—
 —
 31
 —
 31
 —
 —
 —
 31
—
 81
 —
 81
 —
 —
 —
 81
Purchases, sales, issuances and settlements        

              
       

Purchases19
 —
 21
 1
 41
 —
 —
 —
 41
1
 57
 —
 58
 —
 —
 —
 58
Sales—
 —
 (13) —
 (13) —
 —
 —
 (13)—
 —
 —
 —
 —
 —
 —
 —
Settlements(24) —
 —
 —
 (24) —
 —
 —
 (24)(17) —
 —
 (17) —
 —
 —
 (17)
Transfers into Level 3—
 —
 (8) —
 (8) —
 —
 —
 (8)—
 —
(d) 
—
 —
 —
 —
 —
 —
Transfers out of Level 3—
 —
 (4) —
 (4) —
 —
 —
 (4)—
 17
(d) 
—
 17
 —
 —
 —
 17
Balance as of June 30, 2017$683

$21

$589

$41

$1,334

$(256)
$20
 $—

$1,098
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2017$—
 $—
 $43
 $—
 $43
 $—
 $—
 $—
 $43
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)

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

       
Included in net income4
 —
 (46)
(a) 
1
 (41) —
 1
 —
 (40)
Included in noncurrent payables to affiliates13
 —
 —
 —
 13
 —
 —
 (13) —
Included in payable for Zion Station decommissioning—
 1
 —
 —
 1
 —
 —
 —
 1
Included in regulatory assets—
 —
 —
 —
 —
 2
(b) 
—
 13
 15
Change in collateral—
 —
 69
 —
 69
 —
 —
 —
 69
Purchases, sales, issuances and settlements        

       
Purchases36
 1
 90
 3
 130
 —
 —
 —
 130
Sales—
 —
 (15) —
 (15) —
 —
 —
 (15)
Issuances—
 —
 —
 —
 —
 —
 (1) —
 (1)
Settlements(47) —
 —
 —
 (47) —
 —
 —
 (47)
Transfers into Level 3—
 —
 (10) —
 (10) —
 —
 —
 (10)
Transfers out of Level 3—
 —
 8
 (5) 3
 —
 —
 —
 3
Balance as of June 30, 2017$683
 $21
 $589
 $41
 $1,334

$(256) $20
 $—
 $1,098
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2017$2
 $—
 $102
 $1
 $105
 $—
 $1
 $—
 $106
__________
(a)Includes a reduction for the reclassification of $46$80 million and $148$72 million of realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2017,March 31, 2019 and 2018, respectively.
(b)Includes $25$14 million of increasesdecreases in fair value and an increase for realized losses due to settlements of $1$5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2017.March 31, 2019. Includes $5$17 million of decreasesincreases in fair value and an increase for realized losses due to settlements of $7$6 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the sixthree months ended June 30, 2017.March 31, 2018.
(c)The amounts represented are life insurance contracts at Pepco.

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

(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 and six months ended June 30, 2018March 31, 2019 and 2017:2018:
 Generation PHI Exelon
 Operating
Revenues		 Purchased
Power and
Fuel		 
Other, net(a)
 Operating and Maintenance Operating
Revenues		 Purchased
Power and
Fuel		 Operating and Maintenance 
Other, net(a)
Total gains (losses) included in net income for the three months ended June 30, 2018$(191) $78
 $—
 $1
 $(191) $78
 $1
 $—
Total gains (losses) included in net income for the six months ended June 30, 2018144
 (73) 2
 2
 144
 (73) 2
 2
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended June 30, 2018(71) 78
 (4) —
 (71) 78
 —
 (4)
Change in the unrealized gains (losses) relating to assets and liabilities held for the six months ended June 30, 2018238
 25
 (3) —
 238
 25
 —
 (3)
 Generation PHI Exelon
 Operating
Revenues		 Purchased
Power and
Fuel		 Other, net Operating and Maintenance Operating
Revenues		 Purchased
Power and
Fuel		 Operating and Maintenance Other, net
Total gains (losses) included in net income for the three months ended March 31, 2019$(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(a)
 
Other, net(a)
 
Operating
Revenues
 
Purchased
Power and
Fuel
 
Other, net(a)
Total gains (losses) included in net income for the three months ended June 30, 2017$(51) $48
 $1
 $—
 $(51) $48
 $1
Total gains (losses) included in net income for the six months ended June 30, 201737
 (83) 5
 1
 37
 (83) 6
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended June 30, 2017—
 43
 —
 —
 —
 43
 —
Change in the unrealized gains (losses) relating to assets and liabilities held for the six months ended June 30, 2017140
 (38) 3
 1
 140
 (38) 4
 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
__________
(a)Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation, accrued interest on a convertible promissory note at Generation and the life insurance contracts held by PHI and Pepco.
Valuation Techniques Used to Determine Fair Value
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.
Cash Equivalents (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)(All Registrants). The Registrants’ cash equivalents include investments with original maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.
Nuclear Decommissioning TrustNDT Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). The trust fund investments have been established to satisfy Generation’s and CENG's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities and Fixed Income. Generation’s and CENG's NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly

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

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 investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.
Derivative instruments consisting primarily of futures and interest rate swaps to manage risk are recorded at fair value. Over the counter derivatives are valued daily based on quoted prices in active markets and trade in open markets and have been categorized as Level 1. Derivative instruments other than over the counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.
Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models and income models. Investments in loans are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Managed funds are valued using NAV or its

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

equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.
Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. The fair value of private equity and real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.
As of June 30, 2018,March 31, 2019, Exelon and Generation hashave outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $62$127 million, $302$179 million, $178$301 million, and $100$268 million, respectively. These commitments will be funded by Generation’s existing nuclear decommissioning trustNDT funds.

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

Concentrations of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of June 30, 2018.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 June 30, 2018,March 31, 2019, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.
See Note 13 — Nuclear Decommissioning for additional information on the NDT fund investments.
Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE)Pepco). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and 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,

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

bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.
Exelon may utilize fixed-to-floating interest rate swaps which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 10 — Derivative Financial Instruments for additional information on mark-to-market derivatives.
Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)(All Registrants). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

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

The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.
Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd, PHI, Pepco, DPL and ACE)
Nuclear Decommissioning TrustNDT Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). For middle market lending and certain corporate debt securities investments, the fair value is determined using a combination of valuation models including cost models, market models and income models. The valuation estimates are based on discounting the forecasted cash flows, market-based comparable data, credit and liquidity factors, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied for factors such as size, marketability, credit risk and relative performance.
Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Therefore, Generation gains an understanding of the fund managers’ inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the reasonableness of the valuations.

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

has not disclosed such inputs.
Rabbi Trust Investments - Life insurance contracts (Exelon, PHI, Pepco, DPL and ACE)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 gains an understanding of the types of inputs and assumptions used in preparing the valuations and performs procedures to assess the reasonableness of the valuations.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. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.
Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements.
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is

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

generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not

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

typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $3.17$2.52 and $0.47$0.46 for power and natural gas, respectively. Many of the commodity derivatives are short-term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.
On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 10 —Derivative Financial Instruments for 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 June 30, 2018 
Valuation
Technique
 
Unobservable
Input
 Range Fair Value at March 31, 2019 
Valuation
Technique
 
Unobservable
Input
 Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)
 $536
 Discounted
Cash Flow		 Forward power
price		 $9-$141 $278
 Discounted
Cash Flow		 Forward power
price		 $9-$164
 

 
 Forward gas
price		 $1.04-$11.19 

 
 Forward gas
price		 $1.76-$11.63
 

 Option Model Volatility
percentage		 9%-435% 

 Option Model Volatility
percentage		 10%-334%
      
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
 $63
 Discounted
Cash Flow		 Forward power
price		 $9-$139 $64
 Discounted
Cash Flow		 Forward power
price		 $9-$162
      
Mark-to-market derivatives (Exelon and ComEd) $(252) Discounted
Cash Flow		 
Forward heat
rate(c)
 10x-11x $(240) Discounted
Cash Flow		 
Forward heat
rate(c)
 10x-11x
   Marketability
reserve		 4%-8%   Marketability
reserve		 4%-8%
   Renewable
factor		 88%-120%   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, 2017 
Valuation
Technique
 
Unobservable
Input
 Range Fair Value at December 31, 2018 
Valuation
Technique
 
Unobservable
Input
 Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)
 $445
 Discounted
Cash Flow		 Forward power price $3-$124 $443
 Discounted
Cash Flow		 Forward power price $12-$174
 

 
 Forward gas price $1.27-$12.80   
 Forward gas price $0.78-$12.38
 

 Option Model Volatility percentage 11%-139%   Option Model Volatility percentage 10%-277%
      
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
 $26
 Discounted
Cash Flow		 Forward power price $14-$94 $56
 Discounted
Cash Flow		 Forward power price $14-$174
      
Mark-to-market derivatives (Exelon and ComEd) $(256) Discounted Cash Flow 
Forward heat
rate(c)
 9x-10x $(249) Discounted Cash Flow 
Forward heat
rate(c)
 10x-11x
   Marketability reserve 4%-8%   Marketability reserve 4%-8%
   Renewable factor 88%-120%   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 $138$157 million and $81$76 million as of June 30, 2018March 31, 2019 and December 31, 2017,2018, 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.
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-

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

termlong-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.
Derivative authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria

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 related to commodities are recorded at fair value through earnings for the consolidated company, referred to as economic hedges in the following tables. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.
Fair value authoritative guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column. As of June 30, 2018 and DecemberMarch 31, 2017, $9 million and $42019, $6 million of cash collateral held, respectively,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 exception and other non-derivative contracts that are accounted for under the accrual method of accounting.
ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1).
Cash collateral held by PECO and BGE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
In the table below, DPL's economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column.

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 June 30, 2018:March 31, 2019:
 Generation ComEd DPL Exelon Generation ComEd Exelon
Derivatives 
Economic
Hedges
 
Proprietary
Trading
 
Collateral
and
Netting(a)(e)
 
Subtotal(b)
 
Economic
Hedges(c)
 
Economic
Hedges(d)
 
Collateral
and
Netting(a)
 Subtotal 
Total
Derivatives
 
Economic
Hedges
 
Proprietary
Trading
 
Collateral
and
Netting(a)(d)
 
Subtotal(b)
 
Economic
Hedges(c)
 
Total
Derivatives
Mark-to-market derivative assets (current assets) $2,527
 $163
 $(1,893) $797
 $—
 $—
 $—
 $—
 $797
 $2,691
 $118
 $(2,156) $653
 $—
 $653
Mark-to-market derivative assets (noncurrent assets) 1,571
 58
 (1,188) 441
 —
 —
 —
 —
 441
 1,188
 60
 (794) 454
 —
 454
Total mark-to-market derivative assets 4,098
 221
 (3,081) 1,238
 —
 —
 —
 —
 1,238
 3,879
 178
 (2,950) 1,107
 —
 1,107
Mark-to-market derivative liabilities (current liabilities) (2,241) (132) 2,127
 (246) (23) —
 —
 —
 (269) (2,711) (89) 2,485
 (315) (27) (342)
Mark-to-market derivative liabilities (noncurrent liabilities) (1,566) (40) 1,336
 (270) (229) —
 —
 —
 (499) (1,142) (30) 957
 (215) (213) (428)
Total mark-to-market derivative liabilities (3,807) (172) 3,463
 (516) (252) —
 —
 —
 (768) (3,853) (119) 3,442
 (530) (240) (770)
Total mark-to-market derivative net assets (liabilities) $291
 $49
 $382
 $722
 $(252) $—
 $—
 $—
 $470
 $26
 $59
 $492
 $577
 $(240) $337
_________
(a)Exelon Generation and DPLGeneration net all available amounts allowed under the derivative authoritative guidance onin 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 $115$152 million and $54$63 million, respectively, and current and noncurrent liabilities are shown net of collateral of $119$177 million and $94$100 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $382$492 million at June 30, 2018.March 31, 2019.
(c)Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(d)Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
(e)Of the collateral posted/(received), $11$(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, 2017:2018:
 Generation ComEd DPL Exelon Generation ComEd Exelon
Description Economic
Hedges		 Proprietary
Trading		 
Collateral
and
Netting(a)(e)
 
Subtotal(b)
 
Economic
Hedges(c)
 
Economic
Hedges(d)
 
Collateral and
Netting(a)
 Subtotal Total
Derivatives		 Economic
Hedges		 Proprietary
Trading		 
Collateral
and
Netting(a)(d)
 
Subtotal(b)
 
Economic
Hedges(c)
 Total
Derivatives
Mark-to-market derivative assets (current assets) $3,061
 $56
 $(2,144) $973
 $—
 $—
 $—
 $—
 $973
 $3,505
 $105
 $(2,809) $801
 $—
 $801
Mark-to-market derivative assets (noncurrent assets) 1,164
 12
 (845) 331
 —
 —
 —
 —
 331
 1,266
 41
 (862) 445
 —
 445
Total mark-to-market derivative assets 4,225
 68
 (2,989) 1,304
 —
 —
 —
 —
 1,304
 4,771
 146
 (3,671) 1,246
 —
 1,246
Mark-to-market derivative liabilities (current liabilities) (2,646) (43) 2,480
 (209) (21) (1) 1
 —
 (230) (3,429) (74) 3,056
 (447) (26) (473)
Mark-to-market derivative liabilities (noncurrent liabilities) (1,137) (10) 975
 (172) (235) —
 —
 —
 (407) (1,203) (20) 972
 (251) (223) (474)
Total mark-to-market derivative liabilities (3,783) (53) 3,455
 (381) (256) (1) 1
 —
 (637) (4,632) (94) 4,028
 (698) (249) (947)
Total mark-to-market derivative net assets (liabilities) $442
 $15
 $466
 $923
 $(256) $(1) $1
 $—
 $667
 $139
 $52
 $357
 $548
 $(249) $299
_________ 
(a)Exelon Generation and DPLGeneration net all available amounts allowed under the derivative authoritative guidance onin the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
(b)Current and noncurrent assets are shown net of collateral of $169$121 million and $53$51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $167$125 million and $77$60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $466$357 million at December 31, 2017.2018.
(c)Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(d)Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
(e)Of the collateral posted/(received), $(117)$(94) million represents variation margin on the exchanges.

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

Economic Hedges (Commodity Price Risk)
Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis. For the three and six months ended June 30,March 31, 2019 and 2018, and 2017, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the "Net fair value changes related to derivatives" onin the Consolidated Statements of Cash Flows.
 Three Months Ended
June 30,		 Six Months Ended
June 30,		 Three Months Ended
March 31,
 2018 2017 2018 2017 2019 2018
Income Statement Location Gain (Loss) Gain (Loss)
Operating revenues $(7) $(141) $(107) $(96) $(50) $(100)
Purchased power and fuel 96
 (41) (70) (134) 30
 (167)
Total Exelon and Generation $89
 $(182) $(177) $(230) $(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 June 30, 2018,March 31, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 97%-100%90%-93%, 71%-74%64%-67% and 41%-44%38%-41% for 2018, 2019, 2020 and 2020,2021, 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 onin 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 34 — Regulatory Matters of the Exelon 20172018 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 20162018 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-

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

termlong-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 20162018 and previous PGC settlement,settlements, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 20% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s 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;storage, a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas

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

commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas. The hedge program requires that DPL hedge, on a non-discretionary basis, an amount equal to 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. For the three and six months ended June 30,March 31, 2019 and 2018 and 2017 Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also included in the "Net fair value changes related to derivatives" onin the Consolidated Statements of Cash Flows. The Utility Registrants do not execute derivatives for proprietary trading purposes.
  Three Months Ended
June 30,		 Six Months Ended
June 30,
  2018 2017 2018 2017
Income Statement Location Gain (Loss)
Operating revenues $15
 $—
 $17
 $(1)
Interest Rate and Foreign Exchange Risk (All Registrants)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, to manage their interest rate exposure. In addition, the Registrants may utilize interest
  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 derivatives to lock in rate levels,swaps, which are typically designatedtreated 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 manage interest rate risk. ToThe notional amounts were $1,419 million and $1,420 million at March 31, 2019 and December 31, 2018, respectively, for Exelon and $619 million and $620 million at March 31, 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, Generation utilizes foreign currency derivatives, which are treated as economic hedges. Below is a summary of the interest rate and foreign exchange hedge balances as of June 30, 2018:
  Generation Exelon Corporate Exelon
Description 
Derivatives
Designated
as Hedging
Instruments
 
Economic
Hedges
 
Collateral
and
Netting(a)
 Subtotal 
Derivatives
Designated
as Hedging
Instruments
 Total
Mark-to-market derivative assets (current assets) $1
 $5
 $(4) $2
 $—
 $2
Mark-to-market derivative assets (noncurrent assets) 15
 1
 —
 16
 —
 16
Total mark-to-market derivative assets 16
 6
 (4) 18
 —
 18
Mark-to-market derivative liabilities (current liabilities) —
 (3) 4
 1
 —
 1
Mark-to-market derivative liabilities (noncurrent liabilities) —
 —
 —
 —
 (8) (8)
Total mark-to-market derivative liabilities —
 (3) 4
 1
 (8) (7)
Total mark-to-market derivative net assets (liabilities) $16
 $3
 $—
 $19
 $(8) $11
__________
(a)Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral, which are not reflected in the table above.

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

The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2017:
  Generation Exelon Corporate Exelon
Description 
Derivatives
Designated
as Hedging
Instruments
 
Economic
Hedges
 
Collateral
and
Netting(a)
 Subtotal 
Derivatives
Designated
as Hedging
Instruments
 Total
Mark-to-market derivative assets (current assets) $—
 $10
 $(7) $3
 $—
 $3
Mark-to-market derivative assets (noncurrent assets) 3
 —
 —
 3
 3
 6
Total mark-to-market derivative assets 3
 10
 (7) 6
 3
 9
Mark-to-market derivative liabilities (current liabilities) (2) (7) 7
 (2) —
 (2)
Mark-to-market derivative liabilities (noncurrent liabilities) —
 (2) —
 (2) —
 (2)
Total mark-to-market derivative liabilities (2) (9) 7
 (4) —
 (4)
Total mark-to-market derivative net assets (liabilities) $1
 $1
 $—
 $2
 $3
 $5
__________
(a)Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral, which are not reflected in the table above.
Fair Value Hedges (Interest Rate Risk)
For derivative instruments that qualify and are designated as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in earnings immediately. Exelon and Generation include the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps as follows:
   Three Months Ended June 30,
 
Income Statement
Location
 2018 2017 2018 2017
  Gain (loss) on Swaps Gain on Borrowings
ExelonInterest expense $(4) $1
 $7
 $2
          
   Six Months Ended June 30,
 
Income Statement
Location
 2018 2017 2018 2017
  Loss on Swaps Gain on Borrowings
ExelonInterest expense $(11) $(4) $20
 $10
The table below provides the notional amounts of fixed-to-floating hedges outstanding held by Exelonwere $209 million and $268 million at June 30, 2018March 31, 2019 and December 31, 2017:
  As of
  June 30, 2018 December 31, 2017
Fixed-to-floating hedges $800
 $800

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

During the three months ended June 30, 2018, and 2017, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $3 million gain and a $3 million gain, respectively. During the six months ended June 30, 2018 and 2017, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $9 million gain and a $7 million gain, respectively.
Cash Flow Hedges (Interest Rate Risk)
ForThe mark-to-market derivative instruments that qualifyassets and are designated as cash flow hedges, the gain or loss on the effective portion of the derivative will be deferred in AOCI and reclassified into earnings when the underlying transaction occurs. To mitigate interest rate risk, Exelon and Generation enter into floating-to-fixed interest rate swaps to manage a portion of interest rate exposure associated with debt issuances. The table below provides the notional amounts of floating-to-fixed hedges outstanding held by Exelon and Generationliabilities as of June 30, 2018.
  As of
  June 30, 2018 December 31, 2017
Floating-to-fixed hedges $624
 $636

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

The tables below provide the activity of OCI related to cash flow hedges for the three and six months ended June 30, 2018 and 2017, containing information about the changes in the fair value of cash flow hedges and the reclassification from AOCI into results of operations. The amounts reclassified from OCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.
 Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon 
Three Months Ended June 30, 2018 
Income Statement
Location
 Total Cash 
Flow Hedges		 
Total Cash 
Flow Hedges
 
AOCI derivative loss at March 31, 2018   $(9) $(6) 
Effective portion of changes in fair value   4
 3
 
Reclassifications from AOCI to net income Interest Expense 1
 1
 
AOCI derivative loss at June 30, 2018   $(4) $(2) 
        
 Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon 
Six Months Ended June 30, 2018 
Income Statement
Location
 Total Cash 
Flow Hedges		 Total Cash 
Flow Hedges		 
AOCI derivative loss at December 31, 2017   $(16) $(14) 
Effective portion of changes in fair value   11
 11
 
Reclassifications from AOCI to net income Interest Expense 1
 1
 
AOCI derivative loss at June 30, 2018   $(4) $(2) 
        
  Total Cash Flow Hedge OCI Activity, Net of Income Tax
��Generation Exelon 
Three Months Ended June 30, 2017 
Income Statement
Location
 Total Cash 
Flow Hedges		 
Total Cash 
Flow Hedges
 
AOCI derivative loss at March 31, 2017   $(13) $(11) 
Effective portion of changes in fair value   (1) (1) 
AOCI derivative loss at June 30, 2017   $(14) $(12) 
        
  Total Cash Flow Hedge OCI Activity, Net of Income Tax
 Generation Exelon 
Six Months Ended June 30, 2017 
Income Statement
Location
 Total Cash 
Flow Hedges		 
Total Cash
Flow Hedges
 
AOCI derivative loss at December 31, 2016   $(19) $(17) 
Effective portion of changes in fair value   1
 1
 
Reclassifications from AOCI to net income Interest Expense 4
(a) 
4
(a) 
AOCI derivative loss at June 30, 2017   $(14) $(12) 
_________
(a)Amount is net of related income tax expense of $3 million for the six months ended June 30, 2017.
During the three and six months ended June 30, 2018 and 2017, the impact on the results of operations as a result of ineffectiveness from cash flow hedges in continuing designated hedge relationships was immaterial. The estimated amount of existing gains and losses that are reported in

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

AOCI at the reporting date that are expected to be reclassified into earnings within the next twelve months is immaterial.
Economic Hedges (Interest Rate and Foreign Exchange Risk)
Exelon and Generation executes these instruments to mitigate exposure to fluctuations in interest rates or foreign exchange but for which the fair value or cash flow hedge elections were not made. Generation also enters into interest rate derivative contracts and foreign exchange currency swaps ("treasury") to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars.
At June 30, 2018March 31, 2019 and December 31, 2017, Generation had immaterial notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The following table provides notional amounts outstanding held by Exelon and Generation at June 30, 2018 and December 31, 2017 related to foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars.
  As of
  June 30, 2018 December 31, 2017
Foreign currency exchange rate swaps $86
 $94
For the three and six months ended June 30, 2018 and 2017, Exelon and Generation recognized the following net pre-tax mark-to-market gains (losses) in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows.
   Three Months Ended
June 30,		 Six Months Ended
June 30,
   2018 2017 2018 2017
 Income Statement Location Gain (Loss)
GenerationOperating Revenues $2
 $(2) $5
 $(3)
GenerationPurchased Power and Fuel (1) —
 (3) —
Total Generation  $1
 $(2) $2
 $(3)
   Three Months Ended
June 30,		 Six Months Ended
June 30,
   2018 2017 2018 2017
 Income Statement Location Gain (Loss)
ExelonOperating Revenues $2
 $(2) $5
 $(3)
ExelonPurchased Power and Fuel (1) —
 (3) —
Total Exelon  $1
 $(2) $2
 $(3)

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

Proprietary Trading (Interest Rate and Foreign Exchange Risk)
Generation also executes derivative contracts for proprietary trading purposes to hedge risk associated with the interest rate and foreign exchange components of underlying commodity positions. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. For the three and six months ended June 30, 2018 and for the three months ended June 30, 2017,March 31, 2019 and 2018 were not material for Exelon and Generation recognized no net pre-tax commodity mark-to-market gains or losses. For the six months ended June 30, 2017, Exelon and Generation recognized a $1 million net pre-tax commodity mark-to-market loss.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. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

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 June 30, 2018.March 31, 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 $47$36 million, $23$31 million, $23$27 million, $31$37 million, $5 million and $4 million as of June 30, 2018,March 31, 2019, respectively. 
Rating as of June 30, 2018Total Exposure Before Credit Collateral 
Credit Collateral(a)
 Net Exposure Number of Counterparties Greater than 10% of Net Exposure Net Exposure of Counterparties Greater than 10% of Net Exposure
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
Investment grade$823
 $—
 $823
 1
 $206
$819
 $11
 $808
 1
 $135
Non-investment grade90
 30
 60
 

 

86
 39
 47
 

 

No external ratings                  
Internally rated — investment grade228
 —
 228
 

 

162
 —
 162
 

 

Internally rated — non-investment grade78
 13
 65
 

 

87
 7
 80
 

 

Total$1,219
 $43
 $1,176
 1
 $206
$1,154
 $57
 $1,097
 1
 $135
 
Net Credit Exposure by Type of Counterparty As of
June 30, 2018		 As of
March 31, 2019
Financial institutions $97
 $13
Investor-owned utilities, marketers, power producers 627
 762
Energy cooperatives and municipalities 392
 287
Other 60
 35
Total $1,176
 $1,097
_________ 
(a)As of June 30, 2018,March 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $22$37 million of cash and $21$19 million of letters of credit. The credit collateral does not include non-liquid collateral.
ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on daily, updated forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price on a given day, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of June 30, 2018,March 31, 2019, ComEd’s net credit exposure to suppliers was less than $1$2 million.
ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 34 — Regulatory Matters of the Exelon 20172018 Form 10-K for additional information.
PECO’s unsecured credit used by the suppliers represents PECO’s net credit exposure. As of June 30, 2018,March 31, 2019, PECO had no material net credit exposure to its electric suppliers.

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

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. As of June 30, 2018,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 34 — Regulatory Matters of the Exelon 20172018 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 June 30, 2018,March 31, 2019, BGE's net credit exposure to suppliers was immaterial.
BGE’s regulated gas business is exposed to market-price risk. At June 30, 2018, BGE hadMarch 31, 2019, BGE's credit exposure of approximately $5 million related to off-system sales, which is mitigated by parental guarantees, letters of credit or right to offset clauses within other contracts with those third-party suppliers.suppliers, was immaterial.
Pepco’s, DPL's and ACE's power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL's and ACE's net credit exposure. As of June 30, 2018,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 32 — Regulatory Matters of the Exelon 20172018 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 June 30, 2018,March 31, 2019, DPL's credit exposure under its natural gas supply and asset management agreements with investment grade suppliers was immaterial.
Collateral (All Registrants)
As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on

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

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

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 June 30, 2018 December 31, 2017 March 31, 2019 December 31, 2018
Gross fair value of derivative contracts containing this feature(a)
 $(1,699) $(926) $(1,667) $(1,723)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)
 1,250
 577
 1,177
 1,105
Net fair value of derivative contracts containing this feature(c)
 $(449) $(349) $(490) $(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 posted of $420$542 million and letters of credit posted of $424$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 $60 million as of June 30, 2018 for external counterparties with derivative positions. Generation had cash collateral posted of $497 million and letters of credit posted of $293 million and cash collateral held of $35 million and letters of credit held of $33$44 million at December 31, 20172018 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 $1.5$1.9 billion and $1.8$2.1 billion as of June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
Generation’s and Exelon’sExelon's interest rate swaps contain provisions that, in the event of a merger, if Generation’sExelon’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 June 30, 2018, Generation's andMarch 31, 2019, Exelon's swaps were in an asseta liability position of $19 million and $11 million, respectively.

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

that is not material.
See Note 2524 — Segment Information of the Exelon 20172018 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 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 June 30, 2018,March 31, 2019, ComEd held $5$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 June 30, 2018,March 31, 2019, ComEd held $14$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 June 30, 2018,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 June 30, 2018,March 31, 2019, it would have been required to post approximately $8 million of collateral to its counterparties. See Note 34 — Regulatory Matters of the Exelon 20172018 Form 10-K for additional information.
PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating

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

from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of June 30, 2018,March 31, 2019, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of June 30, 2018,March 31, 2019, PECO could have been required to post approximately $20$34 million of collateral to its counterparties.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.
BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of June 30, 2018,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 June 30, 2018,March 31, 2019, BGE could have been required to post approximately $36$46 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 June 30, 2018,March 31, 2019, DPL could have been required to post an additional amount of approximately $11$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.

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

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 Registrantsfollowing table reflects the Registrants' commercial paper programs as of March 31, 2019 and December 31, 2018. Generation and PECO had the following amounts ofno commercial paper borrowings outstanding as of June 30, 2018both March 31, 2019 and December 31, 2017:2018.
Commercial Paper Borrowings June 30, 2018 December 31, 2017
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 $628
 $427
$629
 $89
 2.63% 2.15%
ComEd 320
 —
322
 —
 2.64% 2.14%
PECO 50
 —
BGE 136
 77
106
 35
 2.59% 2.18%
PHI(a)
 122
 350
201
 54
 2.62% 2.15%
Pepco —
 26
PEPCO105
 40
 2.62% 2.24%
DPL —
 216
5
 —
 2.61% 2.07%
ACE 122
 108
91
 14
 2.62% 2.21%
_________
(a)PHI reflects the commercial paper borrowings outstanding of Pepco, DPL and ACE.
Short-Term LoanSee Note 13— Debt and Credit Agreements
On January 13, 2016, PHI entered into a $500 million term loan agreement, which was amended on March 28, 2016. The net proceeds of the loan were used to repay PHI's outstanding commercial paper andExelon 2018 Form 10-K for general corporate purposes. Pursuant toadditional information on the loan agreement, as amended, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1%, and all indebtedness thereunder is unsecured. On March 23, 2017, the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement was fully repaid and the loan terminated.  On March 23, 2017, Exelon Corporate entered into a similar type term loan for $500 million which expired March 22, 2018.  The loan agreement was renewed on March 22, 2018 and will expire on March 21, 2019. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1% and all indebtedness thereunder is unsecured.
On May 23, 2018, ACE entered into two term loan agreements in the aggregate amount of $125 million, which expire on May 22, 2019. Pursuant to the term loan agreements, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.55% and all indebtedness thereunder is unsecured.
Credit Agreements
As of March 15, 2018, theRegistrants’ credit agreement for a Generation bilateral credit facility of $30 million was amended to increase the overall facility size to $95 million. This facility will solely be used by Generation to issue letters of credit.facilities.

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

Short-Term Loan Agreements
On May 26,March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million, which was renewed on March 22, 2018 eachwith 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 Registrants' respective syndicated revolvingloan 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 facilities had their maturity dates extendedagreement establishing a $100 million bilateral credit facility. The facility will mature in March 2021. This facility will solely be used by Generation to May 26, 2023.issue letters of credit.
Long-Term Debt
Issuance of Long-Term Debt
During the sixthree months ended June 30, 2018,March 31, 2019, the following long-term debt was issued:
Company Type Interest Rate Maturity Amount Use of Proceeds Type Interest Rate Maturity Amount Use of Proceeds
Generation Energy Efficiency Project Financing 3.72% September 30, 2018 $4
 Funding to install energy conservation measures for the Smithsonian Zoo project. Energy Efficiency Project Financing 3.95% August 31, 2020 $2
 Funding to install energy conservation measures for the Fort Meade project.
Generation Energy Efficiency Project Financing 3.17% April 30, 2018 $1
 Funding to install energy conservation measures in Brooklyn, NY.
Generation Energy Efficiency Project Financing 2.61% September 30, 2018 $4
 Funding to install energy conservation measures for the Pensacola project.
Generation Energy Efficiency Project Financing 4.17% January 1, 2019 $1
 Funding to install energy conservation measures for the General Services Administration Philadelphia project.
Generation Energy Efficiency Project Financing 4.26% May 1, 2019 $3
 Funding to install energy conservation measures for the National Institutes of Health Multi-Buildings Phase II project.
ComEd First Mortgage Bonds, Series 124 4.00% March 1, 2048 $800
 Refinance one series of maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and to fund general corporate purposes. 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 3.90% March 1, 2048 $325
 Refinance a portion of maturing mortgage bonds.
PECO Loan Agreement 2.00% June 20, 2023 $50
 Funding to implement Electric Long-term Infrastructure Improvement Plan
Pepco First Mortgage Bonds 4.27% June 15, 2048 $100
 Repay existing indebtedness and for general corporate purposes
DPL First Mortgage Bonds 4.27% June 15, 2048 $200
 Repay existing indebtedness and for general corporate purposes
Debt Covenants
12.    Income Taxes (All Registrants)As of March 31, 2019, the Registrants are in compliance with debt covenants, except for Antelope Valley's nonrecourse debt event of default as discussed below.
Corporate Tax Reform (All Registrants)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, 2019, $502 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) through a PPA. On December 22, 2017, President Trump signed the TCJA into law. The TCJA makes many significant changes to the Internal Revenue Code, including, but not limited to, (1) reducingJanuary 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. federal corporate tax rate from 35%Bankruptcy Code, which created an event of default for Antelope Valley’s nonrecourse debt that provides the lender with a right to 21%; (2) creatingaccelerate amounts outstanding under the loan such that they would become immediately due and payable. As a 30% limitation on deductible interest expense (not applicable to regulated utilities); (3) allowing 100% expensing for the cost of qualified property (not applicable to regulated utilities); (4) eliminating the domestic production activities deduction; (5) eliminating the corporate alternative minimum tax and changing how existing alternative minimum tax credits can be realized; and (6) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017. The most significant change that impacts the Registrants is the reductionresult of the corporate federal income tax rateongoing event of default and the absence of a waiver from 35% to 21% beginning January 1, 2018.
Pursuant to the enactment oflender foregoing their acceleration rights, the TCJA, the Registrants remeasured their existing deferred income tax balancesdebt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets as of DecemberMarch 31, 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 reflect the decreaseand are pledged as collateral for this financing. The loan is scheduled to mature on November 28, 2024. As of March 31, 2019, $834 million was outstanding.
Although Antelope Valley’s debt is in default, it is nonrecourse to EGR IV. However, if in the corporate income tax ratefuture Antelope Valley were to file for bankruptcy protection as a result of events culminating from 35% to 21%, which resulted in a material decrease to their net deferred income tax liability balances as shown in the table below. Generation recorded a corresponding net decrease to income tax expense, while the Utility Registrants recorded corresponding regulatory liabilities or assets to the extent suchPG&E’s bankruptcy proceedings this

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

amounts are probablewould represent an event of settlement or recovery through customer ratesdefault for EGR IV’s debt that would provide the lender with an opportunity to accelerate EGR IV’s debt.
See Note 13— Debt and an adjustment to income tax expense for all other amounts. The amount and timing of potential settlementsCredit Agreements  of the established net regulatory liabilities will be determined by the Utility Registrants’ respective rate regulators, subject to certain IRS “normalization” rules. See Note 6 — Regulatory MattersExelon 2018 Form 10-K for additional information.
The Registrants have completed their assessment of the majority of the applicable provisions in the TCJA and have recorded the associated impacts as of December 31, 2017. As discussed further below, under SAB 118 issued by the SEC in December 2017, the Registrants have recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation for which the impacts could not be finalized upon issuance of the Registrants’ financial statements, but for which reasonable estimates could be determined.
For property acquired and placed-in-service after September 27, 2017, the TCJA repeals 50% bonus depreciation for all taxpayers and in addition provides for 100% expensing for taxpayers other than regulated utilities. As a result, Generation will be required to evaluate the contractual terms of its fourth quarter 2017 capital additions and determine if they qualify for 100% expensing under the TCJA as compared to 50% bonus depreciation under prior tax law. Similarly, the Utility Registrants will be required to evaluate the contractual terms of their fourth quarter 2017 capital additions to determine whether they still qualify for the prior tax law’s 50% bonus depreciation as compared to no bonus depreciation pursuant to the TCJA.
At Generation, any required changes to the provisional estimates during the measurement period related to the above item would result in an adjustment to current income tax expense at 35% and a corresponding adjustment to deferred income tax expense at 21% and such changes could be material to Generation’s future results of operations. At the Utility Registrants, any required changes to the provisional estimates would result in the recording of regulatory assets or liabilities to the extent such amounts are probable of settlement or recovery through customer rates and a net change to income tax expense for any other amounts.
The Registrants expect any final adjustments to the provisional amounts to be recorded by the fourth quarter of 2018, which could be material to the Registrants’ future results of operations or financial positions. The accounting for all other applicable provisions of the TCJA is considered complete basedinformation on our current interpretation of the provisions of the TCJA as enacted as of December 31, 2017.
While the Registrants have recorded the impacts of the TCJA based on their interpretation of the provisions as enacted, it is expected that technical corrections or other forms of guidance will be issued during 2018, which could result in material changes to previously finalized provisions. At this time, most states have not provided guidance regarding TCJA impacts and may issue guidance in 2018 which may impact estimates.

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

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

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

Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:
 Three Months Ended June 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 benefit3.4 4.3 8.1 (3.4) 6.5 6.2 4.7 6.5 7.6
Qualified nuclear decommissioning trust fund income0.2 0.5 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.9) (2.4) (0.2) (0.1) (0.2) (0.2) (0.1) (0.3) (0.3)
Plant basis differences(3.0) — (0.1) (17.2) (0.7) (1.2) (2.0) — (0.2)
Production tax credits and other credits(1.7) (4.9) (0.1) — — — — — —
Noncontrolling interests(1.5) (4.5) — — — — — — —
Excess deferred tax amortization(5.2) — (7.6) (0.3) (7.2) (11.3) (11.7) (11.2) (8.8)
Tax Cuts and Jobs Act of 2017(1.3) (1.7) (0.7) — 0.1 0.8 — — —
Other(0.2) (1.3) 0.4 (1.1) 0.8 (0.1) (0.4) 0.1 0.7
Effective income tax rate10.8% 11.0% 20.8% (1.1)% 20.3% 15.2% 11.5% 16.1% 20.0%
  
 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% —%

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

Three Months Ended June 30, 2017(a)
Three Months Ended March 31, 2018
Exelon(b)
 
Generation(c)
 ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:  
State income taxes, net of Federal income tax benefit(53.6) 6.0 5.8 (0.6) 5.0 4.3 3.2 4.6 5.64.1 2.4 8.2 (3.9) 6.3 4.6 1.7 6.3 6.6
Qualified nuclear decommissioning trust fund income64.3 (6.9) — — — — — — —
Qualified NDT fund income(0.4) (1.3) — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(10.8) 0.9 (0.2) (0.1) (0.2) (0.1) (0.1) (0.1) (0.4)(1.3) (4.3) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.3)
Plant basis differences(56.3) — (0.2) (16.0) (0.3) (4.8) (6.2) (1.7) (3.3)(2.7) — 0.1 (14.2) (0.7) (2.6) (3.4) (1.3) (2.6)
Production tax credits and other credits(21.1) 2.3 — — — — — — —(2.8) (9.5) (0.1) — — — — — —
Noncontrolling interests(11.1) 1.2 — — — — — — —(0.7) (2.5) — — — — — — —
Like-Kind Exchange(d)
(109.3) — 5.9 — — — — — —
Excess deferred tax amortization(6.0) — (7.5) (4.8) (8.6) (10.6) (12.8) (7.9) (8.7)
Other11.7 1.0 0.5 0.2 1.3 0.9 (0.2) 0.9 (3.6)(2.8) (1.3) 0.3 0.2 — — (0.3) 0.5 (3.5)
Effective income tax rate(151.2)% 39.5% 46.8% 18.5% 40.8% 35.3% 31.7% 38.7% 33.3%8.4% 4.5% 21.8% (1.8)% 17.9% 12.2% 6.1% 18.4% 12.5%
 Six Months Ended June 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 benefit3.8 3.4 8.1 (3.6) 6.4 5.5 3.7 6.4 7.2
Qualified nuclear decommissioning trust fund income(0.1) (0.4) — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(1.1) (3.3) (0.2) (0.1) (0.1) (0.2) (0.1) (0.3) (0.3)
Plant basis differences(2.8) — — (15.6) (0.7) (1.8) (2.5) (0.7) (1.3)
Production tax credits and other credits(2.3) (7.2) (0.1) — — — — — —
Noncontrolling interests(1.1) (3.5) — — — — — — —
Excess deferred tax amortization(5.6) — (7.5) (2.7) (8.2) (11.0) (12.1) (9.4) (8.8)
Tax Cuts and Jobs Act of 2017(0.6) (0.9) (0.3) — — 0.5 — — —
Other(1.7) (1.3) 0.1 (0.4) 0.2 (0.1) (0.4) 0.4 (1.1)
Effective income tax rate9.5% 7.8% 21.1% (1.4)% 18.6% 13.9% 9.6% 17.4% 16.7%

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

 
Six Months Ended June 30, 2017(a)
 
Exelon(b)
 Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit(0.9) (10.9) 5.3 (0.1) 5.1 4.6 3.8 5.1 5.6
Qualified nuclear decommissioning trust fund income5.5 42.8 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.7) (4.5) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.4)
Plant basis differences(4.2) — (0.2) (14.3) (0.7) (4.3) (6.0) (1.8) (3.3)
Production tax credits and other credits(1.3) (10.3) — — — — — — —
Noncontrolling interests(0.3) (2.6) — — — — — — —
Merger expenses(e)

(11.2) (11.4) — — — (23.8) (16.2) (15.1) (85.3)
FitzPatrick bargain purchase gain(6.4) (50.1) — — — — — — —
Like-Kind Exchange(d)
(3.6) — 2.9 — — — — — —
Other0.2 (3.8) 0.4 (0.1) 0.3 — (0.7) 1.0 (1.6)
Effective income tax rate12.1% (15.8)% 43.2% 20.4% 39.6% 11.3% 15.8% 24.0% (50.0)%
_________
(a)Exelon retrospectively adopted the new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. The effective income tax rates are recast to reflect the impact of the new standard.
(b)The effective tax rate for the three months ended June 30, 2017 is disproportionately impacted due to the decline in consolidated pre-tax GAAP earnings as compared to the federal and state tax impacts of the Like-kind exchange, tax credits, Plant basis differences, and Qualified nuclear decommissioning trust fund income.
(c)Generation recognized a loss before income taxes for the three months ended June 30, 2017. As a result, positive percentages represent an income tax benefit for the period presented.
(d)Exelon and ComEd recorded the impact of the IRS's finalization of the LKE computation in the second quarter of 2017.
(e)Includes a remeasurement of uncertain federal and state income tax positions.
Accounting for Uncertainty in Income Taxes
The Registrants have the following unrecognized tax benefits as of June 30, 2018March 31, 2019 and December 31, 2017:2018:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
June 30, 2018$732
 $454
 $2
 $—
 $120
 $135
 $68
 $21
 $14
 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, 2017$743
 $468
 $2
 $—
 $120
 $125
 $59
 $21
 $14
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
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.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(DollarsIn 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 millions, except per share data, unless otherwise noted)

the first quarter of 2019.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
Like-Kind Exchange
As of June 30, 2018, Exelon and ComEd have approximately $33 million and $2 million, respectively, of unrecognized federal and state income tax benefits that could significantly decrease within the 12 months after the reporting date due to a final resolution of the like-kind exchange litigation described below. The recognition of these unrecognized tax benefits would decrease Exelon and ComEd's effective tax rate.
Settlement of Income Tax Audits, Refund Claims, and Litigation
As of June 30, 2018,March 31, 2019, Exelon, Generation, BGE, PHI Pepco, DPL and ACE have approximately $681$425 million, $458$411 million, $120 million, $103 million, $68 million, $21$14 million and $14 million of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, and the outcomes of pending court cases. Of the above unrecognized tax benefits, Exelon and Generation have $444$411 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefits related to BGE, Pepco, DPL, and ACE, if recognized, may be included in future regulated base rates and that portion would have no impact to the effective tax rate.
As a result of a court decision issued in July 2018 to an unrelated taxpayer, Exelon's and Generation’s unrecognized federal and state tax benefits may increase in the third quarter 2018 by as much as $75 million. As much as $25 million of this increase could impact Exelon's and Generation’s effective tax rate and result in a charge to earnings in the third quarter 2018.
Other Income Tax Matters
Like-Kind Exchange (Exelon and ComEd)
Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities. As previously disclosed, Exelon terminated its investment in one of the leases in 2014 and the remaining two leases were terminated in 2016.
The IRS asserted that the Exelon purchase and leaseback transaction was substantially similar to a leasing transaction, known as a SILO, which is a listed transaction that the IRS has identified as a potentially abusive tax shelter. Thus, they disagreed with Exelon's position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999. In 2013, the IRS issued a notice of deficiency to Exelon and Exelon filed a petition to initiate litigation in the United States Tax Court. In 2016, the Tax Court held that Exelon was not entitled to defer gain on the transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for $90 million in penalties and interest on the penalties. Exelon has fully paid the amounts assessed resulting from the Tax Court decision.
In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit. Oral argument was held in May 2018 and a decision is expected later this year.

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

State Income Tax Law Changes
On April 24, 2018, Maryland enacted companion bills, House Bill 1794decrease the effective tax rate. The unrecognized tax benefits related to PHI and Senate Bill 1090, providing for a phaseACE, if recognized, may be included in of a single sales factor apportionment formula from the current three factor formula for determining an entity's Maryland state income taxes. The single sales factor will be fully phased in by 2022.
In the second quarter of 2018, Exelon, Generation, PHI, Pepcofuture regulated base rates and DPL recorded a one-time increase to deferred income taxes of approximately $16 million, $5 million, $17 million, $16 million and $1 million, respectively. At PHI, Pepco and DPL, the increasethat portion would have no impact to the Maryland deferred incomeeffective tax liability was offset by regulatory assets. Further, the change in tax law is not expected to have a material ongoing impact to Exelon's, Generation's, PHI's, Pepco's or DPL's future results of operations.rate.
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 following table provides a rollforward of the nuclear decommissioning ARO reflected onin Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 20172018 to June 30, 2018:March 31, 2019:
Nuclear decommissioning ARO at December 31, 2017(a)
$9,662
Nuclear decommissioning ARO at December 31, 2018 (a)(b)
$10,005
Net increase due to changes in, and timing of, estimated future cash flows223
Accretion expense237
120
Net increase due to changes in, and timing of, estimated future cash flows32
Costs incurred related to decommissioning plants(10)(19)
Nuclear decommissioning ARO at June 30, 2018(a)
$9,921
Nuclear decommissioning ARO at March 31, 2019 (a)(b)
$10,329
_________
(a)Includes $99$41 million and $13$22 million foras the current portion of the ARO at June 30, 2018March 31, 2019 and December 31, 2017,2018, respectively, which is included in Other current liabilities onin Exelon’s and Generation’s Consolidated Balance Sheets.
(b)Includes $760 million and $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at March 31, 2019 and December 31, 2018, respectively. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.
During the sixthree months ended June 30, 2018,March 31, 2019, Exelon's and Generation’s total nuclear ARO increased by approximately $259$324 million, primarily reflecting the impacts of ARO updates completed during first quarter 2019 and the accretion of the ARO liability due to the passage of timetime. The first quarter 2019 ARO update includes 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 impactimpacts of revised decommissioning cost estimates for TMI which incorporate site specific decommissioning planning activities in anticipation of its September 2019 shutdown date. Approximately $85 million of the February 2, 2018 announcement to retire Oyster Creek at the end of its current operating cycle by October 2018. Refer to Note 8 — Early Plant Retirements for additional information regarding the announced early retirement of Oyster Creek.
Nuclear Decommissioning Trust Fund Investments
NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established forTMI ARO adjustment resulted in a particular unit may not be used to fund the decommissioning obligations of any other unit.
The NDT funds associated with Generation’s nuclear units have been funded with amounts collected from the previous ownersdecrease in Operating and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these

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

collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2018, and the effective rates currently yield annual collections of approximately $4 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2023. See Note 15 — Asset Retirement Obligations of Exelon's 2017 Form 10-K, for information regarding the amount collected from PECO ratepayers for decommissioning costs.
Exelon and Generation had NDT fund investments totaling $13,263 million and $13,349 million at June 30, 2018 and December 31, 2017, respectively.
The following table provides net unrealized gains (losses) on NDT funds for the three and six months ended June 30, 2018 and 2017:
 Exelon and Generation Exelon and Generation
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2018 2017 2018 2017
Net unrealized (losses) gains on decommissioning trust funds — Regulatory Agreement Units(a)
$(194) $(13) $(268) $210
Net unrealized (losses) gains on decommissioning trust funds — Non-Regulatory Agreement Units(b)(c)
(120) 70
 (215) 235
_________
(a)Net unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.
(b)Excludes $4 million and $(2) million of net unrealized gains (losses) related to the Zion Station pledged assets for the three months ended June 30, 2018 and 2017, respectively. Excludes $2 million and $(2) million of net unrealized gains (losses) related to the Zion Station pledged assets for the six months ended June 30, 2018 and 2017, respectively. Net unrealized gains (losses) related to Zion Station pledged assets are included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.
(c)Net unrealized gains (losses) related to Generation’s NDT funds with Non-Regulatory Agreement Units are included in Other, net on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net onmaintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. InterestSee Note 8 — Early Plant Retirements for additional information.
NDT Funds (Exelon and dividends earned on theGeneration)
Exelon and Generation had NDT fund investmentsfunds totaling $13,345 million and $12,695 million at March 31, 2019 and December 31, 2018, respectively. The NDT funds include $881 million and $890 million at March 31, 2019 and December 31, 2018, respectively, related to Oyster Creek NDT funds which are classified as Assets held for the Regulatory Agreement Units are eliminatedsale in Other, net on Exelon’sExelon's and Generation’sGeneration's Consolidated Statement of Operations and Comprehensive Income.
Balance Sheets. See Note 3 — Regulatory MattersMergers, Acquisitions and Note 26 — Related Party Transactions of the Exelon 2017 Form 10-KDispositions for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.
Zion Station Decommissioning
On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 15 — Asset Retirement Obligations of the Exelon 2017 Form 10-K foradditional information regarding the specific treatmentannounced pending sale of assets, includingOyster Creek. The NDT funds also include $163 million and decommissioning liabilities transferred in$144 million for the transaction.

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

ZionSolutions is subject to certain restrictions on its ability to request reimbursements fromcurrent portion of the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Stationat March 31, 2019 and December 31, 2018, respectively, which are included in Other current assets did not qualify for asset sale accounting treatmentin Exelon's and as a result, the related NDT funds were reclassified to Pledged assets for Zion Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’sGeneration's Consolidated Balance Sheets. Changes in the valueSee Note 17 — Supplemental Financial Information for additional information on activities of the Zion Station NDT assets, net of applicable taxes, are recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. Following ZionSolutions’ completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $117 million which is included within the nuclear decommissioning ARO at June 30, 2018. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at June 30, 2018 and December 31, 2017:funds.
 Exelon and Generation
 June 30, 2018 December 31, 2017
Carrying value of Zion Station pledged assets(a)
$21
 $39
Payable to Zion Solutions(b)(c)
20
 37
Cumulative withdrawals by Zion Solutions to pay decommissioning costs(d)
962
 942
_________
(a)Included in Other current assets within Exelon's and Generation's Consolidated Balance sheets.
(b)Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized.
(c)Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.
(d)Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings.
NRC Minimum Funding Requirements (Exelon and Generation)
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.
Generation filed its biennial decommissioning funding status report with the NRC on March 30, 2017 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions (see Zion Station Decommissioning above). The status report demonstrated adequate decommissioning funding assurance for all units except for Peach Bottom unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom unit 1 is provided by the NDT fund in addition to collections from PECO ratepayers. As discussed under Nuclear Decommissioning Trust Fund Investments above, the amount collected from PECO ratepayers has been adjusted effective January 1, 2018.

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

On March 28, 2018, Generation submittedfiled its annualbiennial decommissioning funding status report with the NRC on April 1, 2019 for shutdown reactors, reactors within five years of shut downall units except for Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above), and reactor involved in an acquisition. ThisZionSolutions, LLC. The status report reflected the status ofdemonstrated adequate decommissioning funding assurance as of December 31, 20172018 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 an updatein the April 1, 2019 submittal. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the acquisition of FitzPatrick on March 31, 2017, the early retirement of TMI announced on May 30, 2017, an adjustment for the February 2, 2018 announced retirement date of Oyster Creek,NDT fund, collections from PECO ratepayers, and the updated status of Peach Bottom unit 1 based on the newability to adjust those collections rate described above. As of December 31, 2017, Generation provided adequate decommissioning funding assurance for all of its shutdown reactors, reactors within five years of shutdown, and reactor involved in an acquisition.
Generation will file its next decommissioning funding status reportaccordance with the NRC by March 31, 2019. This report will reflectapproved PAPUC tariff. No additional actions are required aside from the status of decommissioning funding assurance as of December 31, 2018. A shortfall at any unit could necessitate that Generation addressPAPUC filing in accordance with the shortfall by, among other things, obtaining a parental guarantee for Generation's sharetariff. See Note 15 — Asset Retirement Obligations of the funding assurance. However,Exelon 2018 Form 10-K for information regarding the amount of any guarantee or other assurance will ultimately depend on thecollected from PECO ratepayers for decommissioning approach, the associated level of costs, and the decommissioning trust fund investment performance going forward.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.
DuringEffective January 1, 2019, Exelon merged the first quarter of 2017, in connection withExelon Corporation Cash Balance Pension Plan (CBPP) into the acquisition of FitzPatrick, Exelon established a new qualified pension plan and a new OPEB plan and recorded a provisional obligation for Fitzpatrick employees based on information available at the merger date of $38 million and $11 million, respectively. As permitted by business combinations authoritative guidance, during the third quarter of 2017, Exelon updated those obligations based on a final valuation for FitzPatrick employees asCorporation Retirement Program (ECRP). The merging of the merger date of March 31, 2017. The updated obligations forplans 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 OPEB were $16 milliongains related to the CBPP and $17 million, respectively. See Note 4 — Mergers, Acquisitions and Dispositions for additional informationECRP are being amortized over participants’ average remaining service period of the acquisition of FitzPatrick.merged ECRP rather than each individual plan.
Defined Benefit Pension and Other Postretirement Benefits
During the first quarter of 2018,2019, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2018.2019. This valuation resulted in an increase to the pension and OPEB obligations of $23$75 million and $14$36 million, respectively. Additionally, accumulated other comprehensive loss decreasedincreased by $18$39 million (after tax)(after-tax) and regulatory assets and liabilities increased by $61$53 million and $1decreased by $5 million, respectively.
The majority of the 20182019 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 3.62%4.31%. The majority of the 20182019 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.60%6.67% for funded plans and a discount rate of 3.61%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 six months ended June 30, 2018March 31, 2019 and 2017.2018.
Pension Benefits
Three Months Ended June 30,		 Other Postretirement Benefits
Three Months Ended June 30,		Pension Benefits
Three Months Ended March 31,		 Other Postretirement Benefits
Three Months Ended March 31,
2018 
2017(a)
 2018 
2017(a)
2019 2018 2019 2018
Components of net periodic benefit cost:              
Service cost$102
 $97
 $28
 $28
$89
 $101
 $24
 $28
Interest cost200
 211
 44
 46
221
 201
 47
 43
Expected return on assets(313) (299) (43) (41)(307) (312) (38) (43)
Amortization of:              
Prior service cost (benefit)—
 1
 (47) (47)—
 —
 (45) (46)
Actuarial loss157
 150
 16
 15
104
 157
 11
 16
Settlement charges1
 2
 —
 —
Net periodic benefit cost$147
 $162
 $(2) $1
$107
 $147
 $(1) $(2)

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

 

 

 

Service cost$202
 $191
 $56
 $54
Interest cost401
 422
 88
 91
Expected return on assets(626) (598) (87) (82)
Amortization of:       
Prior service cost (benefit)1
 1
 (93) (94)
Actuarial loss314
 302
 33
 31
Settlement charges1
 2
 —
 —
Net periodic benefit cost$293

$320

$(3)
$—
_________
(a)FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.

The amounts below represent Exelon's, Generation's, ComEd's, PECO's, BGE's, BSC's, PHI's, Pepco's, DPL's, ACE's, and PHISCO's allocated portion of theACE's pension and postretirement benefit plan costs. As a result of new pension guidance effective on January 1, 2018, certain balances have been reclassified on Exelon’s Consolidated Statements of Operations and Comprehensive Income for the three and six months ended June 30, 2017. The amounts below represent the Registrants’ as well as BSC's and PHISCO's pension and postretirement benefit plan net periodic benefit costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment, net, for the three and six months ended June 30,March 31, 2019 and 2018, and 2017, while the non-service cost components are included in Other, net and Regulatory assets for the three and six months ended June 30, 2018March 31, 2019 and in Other, net and Property, plant and equipment for the three and six months ended June 30, 2017.2018. For the Registrants other than Exelon, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant and equipment, onnet in their consolidated financial statements for the three and six months ended June 30, 2018March 31, 2019 and 2017.2018.
  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

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

  Three Months Ended June 30, Six Months Ended June 30,
Pension and Other Postretirement Benefit Costs 2018 2017 2018 2017
Exelon(a)(b)
 $145
 $163
 $290
 $320
Generation(b)
 51
 59
 100
 113
ComEd 44
 44
 88
 87
PECO 5
 7
 10
 14
BGE 15
 16
 30
 32
BSC(c)
 13
 13
 28
 26
PHI(a)
 17
 24
 34
 48
Pepco 3
 6
 8
 13
DPL 2
 3
 3
 6
ACE 3
 3
 6
 7
PHISCO(d)
 9
 12
 17
 22
_________
(a)Exelon reflects the consolidated pension and other postretirement benefit costs of Generation, ComEd, PECO, BGE, BSC, and PHI. PHI reflects the consolidated pension and other postretirement benefit costs of Pepco, DPL, ACE, and PHISCO.
(b)FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.
(c)These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, ACE or PHISCO amounts above.
(d)These amounts represent amounts billed to Pepco, DPL and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above.
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 six months ended June 30,March 31, 2019 and 2018, and 2017, respectively.
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended
March 31,
Savings Plan Matching Contributions 2018 2017 2018 2017 2019 2018
Exelon(b)
 $50

$33

$82

$63
 $31

$32
Generation(b)
 28
 14
 43
 28
 13
 15
ComEd 8
 8
 15
 15
 7
 7
PECO 2
 2
 4
 4
 2
 2
BGE 2
 3
 4
 4
 2
 2
BSC(c)
 7
 3
 10
 5
PHI(a)
 3
 3
 6
 7
PHI 4
 3
Pepco 1
 1
 2
 2
 1
 1
DPL 1
 1
 1
 1
 1
 1
ACE —
 —
 1
 1
 1
 —
PHISCO(d)
 1
 1
 2
 3

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

_________
(a)Exelon reflects the consolidated savings plan matching contributions of Generation, ComEd, PECO, BGE, BSC, and PHI. PHI reflects the consolidated savings plan matching contributions of Pepco, DPL, ACE, and PHISCO.
(b)FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.
(c)These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, ACE or PHISCO amounts above.
(d)These amounts represent amounts billed to Pepco and DPL through intercompany allocations. These amounts are not included in Pepco or DPL amounts above.
15. Changes in Accumulated Other Comprehensive Income (Exelon Generation and PECO)Generation)
The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the sixthree months ended June 30, 2018March 31, 2019 and 2017:2018:
Six Months Ended June 30, 2018Gains (Losses) on Cash Flow Hedges Unrealized gains (losses) on Marketable Securities 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates
 Total
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$(14) $10
 $(2,998)
(d) 
$(23) $(1) $(3,026)$(2) $—
 $(2,960) $(33) $—
 $(2,995)
OCI before reclassifications13
 —
 20
 (6) 1
 28
—
 —
 (38) 2
 (1) (37)
Amounts reclassified from AOCI(b)
(1) —
 88
 —
 —
 87
—
 —
 20
 —
 —
 20
Net current-period OCI12
 —
 108
 (6) 1
 115
—
 —
 (18) 2
 (1) (17)
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 (10)
(c) 
—
 —
 —
 (10)
Ending balance$(2) $—
 $(2,890) $(29) $—
 $(2,921)$(2) $—
 $(2,978) $(31) $(1) $(3,012)
Generation(a)
          

          

Beginning balance$(16) $3
 $—
 $(23) $(1) $(37)$(4) $—
 $—
 $(33) $(1) $(38)
OCI before reclassifications13
 —
 —
 (6) 1
 8
—
 —
 —
 2
 (1) 1
Amounts reclassified from AOCI(b)
(1) —
 —
 —
 —
 (1)
Amounts reclassified from AOCI1
 —
 —
 —
 —
 1
Net current-period OCI12
 —
 —
 (6) 1
 7
1
 —
 —
 2
 (1) 2
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 (3)
(c) 
—
 —
 —
 (3)
Ending balance$(4) $—
 $—
 $(29) $—
 $(33)$(3) $—
 $—
 $(31) $(2) $(36)
PECO(a)
          
Beginning balance$—
 $1
 $—
 $—
 $—
 $1
OCI before reclassifications—
 —
 —
 —
 —
 —
Amounts reclassified from AOCI(b)
—
 —
 —
 —
 —
 —
Net current-period OCI—
 —
 —
 —
 —
 —
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard—
 (1)
(c) 
—
 —
 —
 (1)
Ending balance$—
 $—
 $—
 $—
 $—
 $—

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

Six Months Ended June 30, 2017Gains (Losses) on Cash Flow Hedges Unrealized gains (losses) on Marketable Securities 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates
 Total
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$(17) $4
 $(2,610) $(30) $(7) $(2,660)$(14) $10
 $(2,998)
(d) 
$(23) $(1) $(3,026)
OCI before reclassifications1
 2
 (58) 3
 5
 (47)8
 —
 18
 1
 —
 27
Amounts reclassified from AOCI(b)
4
 —
 70
 —
 —
 74
—
 —
 44
 —
 —
 44
Net current-period OCI5
 2
 12
 3
 5
 27
8
 —
 62
 1
 —
 71
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)
—
 (10) —
 —
 —
 (10)
Ending balance$(12) $6
 $(2,598) $(27) $(2) $(2,633)$(6) $—
 $(2,936) $(22) $(1) $(2,965)
Generation(a)
          
          
Beginning balance$(19) $2
 $—
 $(30) $(7) $(54)$(16) $3
 $—
 $(23) $(1) $(37)
OCI before reclassifications1
 —
 —
 3
 6
 10
7
 —
 —
 (1) —
 6
Amounts reclassified from AOCI(b)
4
 —
 —
 —
 —
 4
Amounts reclassified from AOCI—
 —
 —
 —
 —
 —
Net current-period OCI5
 —
 —
 3
 6
 14
7
 —
 —
 (1) —
 6
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)
—
 (3) —
 —
 —
 (3)
Ending balance$(14) $2
 $—
 $(27) $(1) $(40)$(9) $—
 $—
 $(24) $(1) $(34)
PECO(a)
          

Beginning balance$—
 $1
 $—
 $—
 $—
 $1
OCI before reclassifications—
 —
 —
 —
 —
 —
Amounts reclassified from AOCI(b)
—
 —
 —
 —
 —
 —
Net current-period OCI—
 —
 —
 —
 —
 —
Ending balance$—
 $1
 $—
 $—
 $—
 $1
_________
(a)All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI.
(b)See next tables for details about these reclassifications.
(c)Exelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million $3 million and $1$3 million for Exelon Generation and PECO,Generation, respectively. The amounts reclassified related to Rabbi Trusts. See Note 21 — NewSignificant Accounting StandardsPolicies 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 21 — NewSignificant Accounting StandardsPolicies 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 and six months ended June 30, 2018March 31, 2019 and 2017.2018. The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the three and six months ended June 30, 2018March 31, 2019 and 2017.2018.
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 June 30,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 Generation  
Gains (Losses) on cash flow hedges      
Other cash flow hedges $1
 $1
 Interest expense
Total before tax 1
 1
  
Tax benefit —
 —
  
Net of tax $1
 $1
 Comprehensive income
       
Amortization of pension and other postretirement benefit plan items      
Prior service costs(b)
 $23
 $—
  
Actuarial losses(b)
 (83) —
  
Total before tax (60) —
  
Tax benefit 16
 —
  
Net of tax $(44) $—
  
       
Total Reclassifications $(43) $1
 Comprehensive income

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

Six Months Ended June 30, 2018
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
  Exelon Generation  
Gains (Losses) on cash flow hedges      
Other cash flow hedges $1
 $1
 Interest expense
Total before tax 1

1

 
Tax benefit —
 —
  
Net of tax $1
 $1
 Comprehensive income
       
Amortization of pension and other postretirement benefit plan items      
Prior service costs(b)
 $46
 $—
  
Actuarial losses(b)
 (166) —
  
Total before tax (120) —
  
Tax benefit 32
 —
  
Net of tax $(88) $—
  
       
Total Reclassifications $(87) $1
 Comprehensive income
Three Months Ended June 30, 2017
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)
 (81)  
Total before tax (58)  
Tax benefit 24
  
Net of tax $(34)  
     
Total Reclassifications $(34) Comprehensive income

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

Six Months Ended June 30, 2017
Details about AOCI components 
Items reclassified out of AOCI(a)
 Affected line item in the Statement of Operations and Comprehensive Income
  Exelon Generation  
Gains (Losses) on cash flow hedges      
Other cash flow hedges $(7) $(7) Interest expense
Total before tax (7)
(7)
 
Tax benefit 3
 3
  
Net of tax $(4) $(4) Comprehensive income
       
Amortization of pension and other postretirement benefit plan items      
Prior service costs(b)
 $46
 $—
  
Actuarial losses(b)
 (162) —
  
Total before tax (116) —
  
Tax benefit 46
 —
  
Net of tax $(70) $—
  
       
Total Reclassifications $(74) $(4) Comprehensive income
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 (seecost. See Note 14 — Retirement Benefits for additional information).information.

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

The following table presents income tax expense (benefit)benefit (expense) allocated to each component of other comprehensive income (loss) during the three and six months ended June 30, 2018March 31, 2019 and 2017:2018:
Three Months Ended June 30, Six Months Ended
June 30,		Three Months Ended
March 31,
2018 2017 2018 20172019 2018
Exelon          
Pension and non-pension postretirement benefit plans:          
Prior service benefit reclassified to periodic benefit cost$6
 $9
 $12
 $18
$6
 $6
Actuarial loss reclassified to periodic benefit cost(22) (32) (44) (64)(13) (22)
Pension and non-pension postretirement benefit plans valuation adjustment1
 1
 (6) 3
14
 (7)
Change in unrealized (loss) on cash flow hedges(1) (2) (4) (3)
Change in unrealized (loss) on investments in unconsolidated affiliates—
 —
 (1) (3)
Change in unrealized (loss) on marketable securities—
 —
 —
 (1)
Change in unrealized loss on cash flow hedges—
 (3)
Change in unrealized loss on investments in unconsolidated affiliates—
 (1)
Total$(16) $(24) $(43) $(50)$7
 $(27)
          
Generation          
Change in unrealized (loss) on cash flow hedges$(1) $(2) $(4) $(3)
Change in unrealized (loss) on investments in unconsolidated affiliates—
 —
 (1) (2)
Change in unrealized gain (loss) on cash flow hedges$1
 $(3)
Change in unrealized loss on investments in unconsolidated affiliates—
 (1)
Total$(1) $(2) $(5) $(5)$1
 $(4)
16.    Earnings Per Share and Equity (Exelon)
Earnings per Share
Basic earnings per share is computed by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding, including the effect of issuing common stock assuming (i) stock options are exercised, and (ii) performance share awards and restricted stock awards are fully vested under the treasury stock method.
The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock awards on the weighted average number of shares outstanding used in calculating diluted earnings per share:

Three Months Ended June 30,
Six Months Ended June 30,
 2018
2017
2018
2017
Exelon       
Net income attributable to common shareholders$539
 $95
 $1,125
 $1,086
Weighted average common shares outstanding — basic967
 934
 967
 931
Assumed exercise and/or distributions of stock-based awards2
 2
 1
 1
Weighted average common shares outstanding — diluted969
 936
 968
 932

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

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 2 million and 5 million for the three and six months ended June 30, 2018, respectively, and 8 million and 9 million for the three and six months ended June 30, 2017, respectively. There were no equity units related to the PHI Merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the three and six months ended June 30, 2018 and 2017. See Note 19 — Shareholders' Equity of the Exelon 2017 Form 10-K for additional information regarding the equity units.
Under share repurchase programs, 2 million shares of common stock are held as treasury stock with a cost of $123 million as of June 30, 2018.
17. Commitments and Contingencies (All Registrants)
The following is an update to the current status of commitments and contingencies set forth in Note 2322 of the Exelon 20172018 Form 10-K. See Note 45 — Mergers, Acquisitions and Dispositions of the Exelon 20172018 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 June 30, 2018:March 31, 2019:
DescriptionExpected Payment Period Pepco DPL ACE PHI Exelon
Rate credits2016 - 2017 $91
 $67
 $101
 $259
 $259
Energy efficiency2016 - 2021 —
 —
 —
 —
 122
Charitable contributions2016 - 2026 28
 12
 10
 50
 50
Delivery system modernizationQ2 2017 —
 —
 —
 —
 22
Green sustainability fundQ2 2017 —
 —
 —
 —
 14
Workforce development2016 - 2020 —
 —
 —
 —
 17
Other  1
 5
 —
 6
 29
Total commitments  $120
 $84
 $111
 $315
 $513
Remaining commitments  $76
 $12
 $7
 $95
 $140
In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new generation in Maryland, District of Columbia, and Delaware, 27 MWs of which are expected to be completed in 2018. These investments are expected to total approximately $137 million, are expected to be primarily capital in nature, and will generate future earnings at Exelon and Generation. Investment costs will be recognized as incurred and recorded on Exelon's and Generation's financial statements. Exelon has also committed to purchase 100 MWs of wind energy in PJM, to procure 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio
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

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

standards, andIn addition, Exelon is committed to maintain and promote energy efficiency and demand response programsdevelop or to assist in the PHI jurisdictions.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 be recognized as incurred and recorded in Exelon's and Generation's financial statements. As of March 31, 2019, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $97 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 and ACE are not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process and have made other commitments regarding hiring and relocation of positions.
Constellation Merger Commitments (Exelon and Generation)
In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to develop or assist in the development of 285-300 MWs of new generation. Exelon and Generation have incurred $458 million towards satisfying the commitment for new generation development in the State of Maryland, with 220 MW of new generation in operations to date and 10 MW of this commitment satisfied through a liquidated damages payment made in the fourth quarter of 2016. The remaining 55 MW is expected to be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by Generation constructing renewable generating assets. As a result, as of June 30, 2018 Exelon’s and Generation’s Consolidated Balance Sheets include a $50 million liability within Deferred credits and other liabilities for this remaining commitment, to be paid on or before January 15, 2023 unless the period is extended by consent of Exelon and the State of Maryland. See Note 23 - Commitments and Contingencies of the Exelon 2017 Form 10-K for additional information regarding the Constellation Merger Commitments.
Commercial Commitments (All Registrants)
. The Registrants’ commercial commitments as of June 30, 2018,March 31, 2019, representing commitments potentially triggered by future events were as follows:
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Letters of credit (non-debt)(a)
 $1,573
 $1,543
 $2
 $—
 $3
 $—
 $—
 $—
 $—
Letters of credit $1,480
 $1,455
 $6
 $—
 $2
 $8
 $8
 $—
 $—
Surety bonds(b)(a)
 1,395
 1,202
 9
 9
 18
 65
 32
 4
 3
 1,597
 1,376
 51
 9
 17
 40
 32
 5
 3
Financing trust guarantees 378
 —
 200
 178
 —
 —
 —
 —
 —
 378
 —
 200
 178
 —
 —
 —
 —
 —
Guaranteed lease residual values(c)(b)
 22
 —
 —
 —
 —
 22
 7
 9
 6
 26
 —
 —
 —
 —
 26
 8
 11
 7
Total commercial commitments $3,368
 $2,745
 $211
 $187
 $21

$87
 $39
 $13
 $9
 $3,481
 $2,831
 $257
 $187
 $19

$74
 $48
 $16
 $10
_________
(a)Letters of credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. Includes letters of credits issued under credit facility agreements arranged at minority and community banks and nonrecourse debt letters of credits.
(b)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(c)(b)Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $58$68 million, $17$22 million of which is a guarantee by Pepco, $24$28 million by DPL and $16$17 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Nuclear Insurance (Exelon and Generation)
. Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.

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

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of June 30, 2018,March 31, 2019, the current liability limit per incident is $13.1$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 September 10, 2013.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 $12.6$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 $2.8$3.1 billion, however any amounts payable under this secondary layer would be capped at $420$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 $13.1$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 20172018 Form 10-K for additional information on Generation’s operations relating to CENG.
Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.
NEIL may declare distributions to its members as a result of favorable operating experience. In recent years NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all. In March 2018, NEIL declared a supplemental distribution. Generation's portion of the supplemental distribution declared by NEIL was $31 million and was recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income for the six months ended June 30, 2018.
Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $350$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

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

of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by Exelon will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.
For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and 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 onin the Registrants' financial conditions, results of operations and cash flows.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 42 sites, 2021 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 2221 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2022.2023.
PECO has identified 26 sites, 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements and 9 that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.
BGE has identified 13 sites, 9 of which have been remediated and approved by the MDE and 4 that require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2019.
DPL has identified 3 sites, for 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control.

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

The remaining site is under study and the required cost at the site is not expected to be material.
The historical nature of the MGP 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.
As of June 30, 2018March 31, 2019 and December 31, 2017,2018, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
June 30, 2018
Total environmental
investigation and
remediation reserve
 
Portion of total related to
MGP investigation and
remediation
Exelon$453

$305
Generation115
 —
ComEd276
 274
PECO28
 27
BGE6
 4
PHI28

—
Pepco26
 —
DPL1
 —
ACE1
 —
December 31, 2017
Total environmental
investigation and
remediation reserve
 
Portion of total related to
MGP investigation and
remediation
March 31, 2019
Total environmental
investigation and
remediation reserve
 
Portion of total related to
MGP investigation and
remediation
Exelon$466

$315
$486

$347
Generation117
 —
108
 —
ComEd285
 283
320
 318
PECO30
 28
27
 25
BGE5
 4
5
 4
PHI29

—
26

—
Pepco27
 —
24
 —
DPL1
 —
1
 —
ACE1
 —
1
 —

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

Solid and Hazardous Waste
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. On May 29, 2008, the EPA issued a Record of Decision (ROD) approving a landfill cover remediation approach. Generation had previously recorded an estimated liability for its anticipated share of a landfill cover remedy that was estimated to cost approximately $90 million in total. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the supplemental feasibility study to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study. This further analysis was focused on a partial excavation remedial option. The PRPs provided the draft final Remedial Investigation and Feasibility Study (RI/FS) to the EPA in January 2018, which formed the basis for EPA’s proposed remedy selection, as discussed below. ThereIncluding Cotter, there are currently three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.
On February 1,In September 2018 the EPA announcedissued its Record of Decision (ROD) Amendment for the selection of the final remedy. The ROD modified the EPA’s previously proposed remedy involvingplan for partial excavation of the site with an enhanced landfill cover.radiological materials by reducing the depths of the excavation. The proposedROD also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs are negotiating Consent Agreements to design and implement the ROD remedy, was open for public comment through April 23, 2018 and Generation currently expects that a ROD willnegotiations are expected to be issued duringcompleted in the thirdfirst quarter of 2018. Thereafter, the EPA will seek to enter into a Consent Decree with the PRPs to effectuate the remedy, which Generation currently expects will occur in late 2018 or early 2019.2020. The estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred by the PRPs in fully executing the remedy, is approximately $340$280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost for the entire remediation effort.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 ultimate required remediation remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Generation’s associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial conditions, results of operations and cash flows.statements.
On January 16, 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. The PRPs have been provided with a draft statement of work that will form the basis of an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater RI/FS and reimbursement of EPA’s oversight costs. The purposes of this new RI/FS are to define the nature and extent of any groundwater contamination from the West Lake Landfill site, determine the potential risk posed to human health and the environment, and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS for West Lake to be approximately $20 million and Generation has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities will be required and cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible,

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

however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future results of operations and cash flows.
During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent and dangerous conditions at the landfill. The first involved installation by the PRPs of a non-combustible surface cover to protect against surface fires in areas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount to cover its anticipated liability for this interim action, and the work is expected to be completed in 2018. The second action involved EPA's public statement that it will require the PRPs to construct a barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Generation believes that the requirement to build a barrier wall is remote in light of other technologies that have been employed by the adjacent landfill owner. Finally, oneOne of the other PRPs the landfill owner and operator of the adjacent landfill, has indicated that it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial statements.
In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions resultsat 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 operationsthe groundwater RI/FS. The purpose of this RI/FS is to define the nature and cash flows.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.
On
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

In August, 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million from all PRPs. ThePursuant to a series of annual agreements since 2011, the DOJ and the PRPs agreed to tollhave tolled the statute of limitations until August 20182019 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.

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

Benning Road Site (Exelon, Generation, PHI and Pepco)
. In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a Remediation Investigation (RI)/ Feasibility Study (FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The Consent Decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. Pursuant to Exelon's March 23, 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation.
Since 2013, Pepco and Pepco Energy Services (now Generation) have been performing RI work and have submitted multiple draft RI reports to the DOEE. Once the RI work is completed, Pepco and Generation will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Generation will then proceed to develop an FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the RI and FS, and approval by the DOEE, by May 6, 2019.September 16, 2021.
Upon DOEE’s approval of the final RI and FS Reports, Pepco and Generation will have satisfied their obligations under the Consent Decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.
PHI, Pepco and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI and Pepco)
. Contemporaneous with the Benning RI/FS being performed by Pepco and Generation, DOEE and certain federal agencies have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-D.C. boundary line to the confluence of the Anacostia and Potomac Rivers. In March 2016, DOEE released a draft of the river-wideriver-

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 Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning RI/FS. Pepco responded that it will participate in the Consultative Working Group, but its participation is not an acceptance of any financial responsibility beyond the work that will be performed at the Benning Road site described above. In April 2018, DOEE released a draft remedial investigation report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing. Pepco continues outreach efforts as appropriate to the agencies, governmental officials, community organizations and other key stakeholders. A draft Feasibility Study of potential remedies is being prepared by the agencies and is scheduled to be released later this year. In May 2018 the District of Columbia Council extended the deadline for completion

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

of the Record of Decision from June 30, 2018 until December 31, 2019. An appropriate liability for Pepco’s share of investigation costs has been accrued and is included in the table above. Although Pepco has determined that it is probable that costs for remediation will be incurred, Pepco cannot estimate the reasonably possible range of loss at this time and no liability has been accrued for those future costs. ItA draft Feasibility Study of potential remedies and their estimated costs is anticipated thatbeing prepared by the agencies and is expected later in 2019, at which time Pepco will likely be in a better position to estimate thatthe range of loss when the draft Feasibility Study for the Project is released later this year.loss.
In addition to the activities associated with the remedial process outlined above, there is a complementary statutory program that requires an assessment to determine if any natural resources have been damaged as a result of the contamination that is being remediated, and, if so, that a plan be developed by the federal, state and local Trustees responsible for those resources to restore them to their condition before injury from the environmental contaminants. If natural resources are not restored, then compensation for the injury can be sought from the party responsible for the release of the contaminants. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also effectively restore habitat. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process it cannot reasonably estimate the range of loss.
Conectiv Energy Wholesale Power Generation Sites (Exelon, Generation, and PHI)
In July 2010, PHI sold the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI indemnified Calpine for any ISRA compliance remediation costs in excess of $10 million. PHI estimated the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million and recorded a liability for its share of the estimated clean-up costs. Pursuant to Exelon’s March 2016 acquisition of PHI, the Conectiv Energy legal entity was transferred to Generation and the liability for PHI's share of the estimated clean-up costs was also transferred to Generation and is included in the table above as a liability of Generation. The responsibility to indemnify Calpine is shared by PHI and Generation.
Brandywine Fly Ash Disposal Site (Exelon, PHI and Pepco)
In February 2013, Pepco received a letter from the MDE requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.
Pepco has determined that a loss associated with this matter is probable and has recorded an estimated liability, which is included in the table above. Pepco believes that the costs incurred in this matter may be recoverable from NRG under the 2000 sale agreement but has not recorded an associated receivable for any potential recovery.

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

Litigation and Regulatory Matters
PHI Merger (Exelon and PHI)
In July 2015, the OPC, Public Citizen, Inc., the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed motions to stay the MDPSC order approving the Exelon and PHI merger. The Circuit Court judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, CCAN and Public Citizen, Inc. On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed notices of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment that the MDPSC did not err in approving the merger. The OPC and Sierra Club filed petitions seeking further review in the Court of Appeals of Maryland, which is the highest court in Maryland. On June 21, 2017, the Court of Appeals granted discretionary review of the January 27, 2017 decision by the Maryland Court of Special Appeals. The Maryland Court of Appeals will review the OPC argument that the MDPSC did not properly consider the acquisition premium paid to PHI shareholders under Maryland’s merger approval standard and the Sierra Club’s argument that the merger would harm the renewable and distributed generation markets. The two lower courts examining these issues rejected these arguments, which Exelon believes are without merit. All briefs have been filed and oral arguments were presented to the court on October 10, 2017.
Asbestos Personal Injury Claims (Exelon Generation, PECO and ComEd)
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 June 30, 2018March 31, 2019 and December 31, 2017,2018, Generation had recorded estimated liabilities of approximately $80$77 million and $78$79 million, respectively, in total for asbestos-related bodily injury claims. As of June 30, 2018,March 31, 2019, approximately $22$25 million of this amount related to 224239 open claims presented to Generation, while the remaining $58$52 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.
There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases could have a material unfavorable impact on Exelon's and Generation's and PECO's financial conditions, results of operations and cash flows.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 unitsUnits 8 and 9 on the grounds that the total investment in Mystic unitsUnits 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

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

damages for alleged underpaid taxes over the period of the TIF Agreement. Generation vigorously contested the City’s claims before the EACC and will continue to do so in the Massachusetts Superior Court proceeding. Generation continues to believe that the City’s claim lacks merit. Accordingly, Generation has not recorded a liability for payment resulting from such a revocation, nor can Generation estimate a reasonably possible range of loss, if any, associated with any such revocation. Further, it is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2019, could be material to Generation’s results of operations and cash flows.
General (All Registrants)
. The Registrants 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.
Income Taxes
See Note 12 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

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

18.17. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the three and six months ended June 30, 2018March 31, 2019 and 2017.2018.
Three Months Ended June 30, 2018Three Months Ended March 31, 2019
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                                  
Decommissioning-related activities:                                  
Net realized income on decommissioning trust funds(a)
                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units(b)$216
 $216
 $—
 $—
 $—
 $—
 $—
 $—
 $—
$54
 $54
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units143
 143
 —
 —
 —
 —
 —
 —
 —
54
 54
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on decommissioning trust funds                 
Net unrealized gains on NDT funds                 
Regulatory agreement units(b)(194) (194) —
 —
 —
 —
 —
 —
 —
379
 379
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units(120) (120) —
 —
 —
 —
 —
 —
 —
280
 280
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on pledged assets                 
Zion Station decommissioning4
 4
 —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(23) (23) —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(c)
(348) (348) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities26
 26
 —
 —
 —

—
 —
 —
 —
419
 419
 —
 —
 —
 —

—
 —
 —
Investment income6
 5
 —
 —
 —
 —
 —
 —
 —
12
 7
 —
 1
 —
 —
 —
 —
 —
Interest income related to uncertain income tax positions2
 —
 —
 —
 —
 —
 —
 —
 —
1
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity13
 —
 2
 —
 4
 7
 6
 1
 —
22
 —
 5
 3
 5
 9
 6
 1
 2
Non-service net periodic benefit cost(11) —
 —
 —
 —
 —
 —
 —
 —
5
 —
 —
 —
 —
 —
 —
 —
 —
Other8
 (2) 2
 —
 —
 4
 2
 2
 1
8
 4
 3
 —
 —
 3
 1
 2
 1
Other, net$44

$29

$4

$—

$4

$11

$8

$3

$1
$467

$430

$8

$4

$5
 $12

$7

$3

$3

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

 Six Months Ended June 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on decommissioning trust funds(a)
                 
Regulatory agreement units$262
 $262
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units199
 199
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on decommissioning trust funds                 
Regulatory agreement units(268) (268) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units(215) (215) —
 —
 —
 —
 —
 —
 —
Net unrealized gains on pledged assets                 
Zion Station decommissioning2
 2
 —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(1) (1) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities(21) (21) —
 —
 —
 —

—
 —
 —
Investment income10
 7
 —
 —
 —
 —
 —
 —
 —
Interest income related to uncertain income tax positions4
 1
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity31
 —
 8
 2
 8
 13
 12
 1
 —
Non-service net periodic benefit cost(21) —
 —
 —
 —
 —
 —
 —
 —
Other14
 (2) 4
 —
 1
 9
 4
 4
 1
Other, net$17

$(15)
$12

$2

$9
 $22

$16

$5

$1
 Three Months Ended June 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                 
Decommissioning-related activities:                 
Net realized income on decommissioning trust funds(a)
                 
Regulatory agreement units$211
 $211
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units74
 74
 —
 —
 —
 —
 —
 —
 —
Net unrealized (losses) gains on decommissioning trust funds                 
Regulatory agreement units(13) (13) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units70
 70
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                 
Zion Station decommissioning(2) (2) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(160) (160) —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities180
 180
 —
 —
 —

—

—
 —
 —
Investment income2
 1
 —
 —
 —
 —
 —
 —
 —
Interest expense related to uncertain income tax positions(1) —
 —
 —
 —
 —
 —
 —
 —
Penalty income related to uncertain income tax positions1
 —
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity17
 —
 2
 2
 4
 9
 5
 2
 2
Non-service net periodic benefit cost(28) —
 —
 —
 —
 —
 —
 —
 —
Other6
 —
 2
 —
 —
 4
 2
 1
 —
Other, net$177

$181

$4

$2

$4
 $13

$7

$3

$2

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

Six Months Ended June 30, 2017Three Months Ended March 31, 2018
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net                                  
Decommissioning-related activities:                                  
Net realized income on decommissioning trust funds(a)
                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units(b)$280
 $280
 $—
 $—
 $—
 $—
 $—
 $—
 $—
$46
 $46
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units106
 106
 —
 —
 —
 —
 —
 —
 —
56
 56
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on decommissioning trust funds                 
Net unrealized losses on NDT funds                 
Regulatory agreement units(b)210
 210
 —
 —
 —
 —
 —
 —
 —
(75) (75) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units235
 235
 —
 —
 —
 —
 —
 —
 —
(96) (96) —
 —
 —
 —
 —
 —
 —
Net unrealized losses on pledged assets                 
Zion Station decommissioning(2) (2) —
 —
 —
 —
 —
 —
 —
Regulatory offset to decommissioning trust fund-related activities(b)
(396) (396) —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(c)
24
 24
 —
 —
 —
 —
 —
 —
 —
Total decommissioning-related activities433
 433
 —
 —
 —
 —

—
 —
 —
(45) (45) —
 —
 —
 —

—
 —
 —
Investment income (expense)4
 3
 —
 (1) —
 1
 1
 —
 —
Penalty income related to uncertain income tax positions2
 —
 —
 —
 —
 —
 —
 —
 —
Investment income4
 2
 —
 —
 —
 —
 —
 —
 —
Interest income related to uncertain income tax positions2
 1
 —
 —
 —
 —
 —
 —
 —
AFUDC — Equity33
 —
 4
 4
 8
 17
 11
 3
 3
18
 —
 6
 2
 4
 6
 5
 1
 —
Non-service net periodic benefit cost(54) —
 —
 —
 —
 —
 —
 —
 —
(10) —
 —
 —
 —
 —
 —
 —
 —
Other16
 4
 4
 —
 —
 8
 3
 3
 1
3
 (2) 2
 —
 —
 5
 3
 1
 1
Other, net$434

$440

$8

$3

$8
 $26

$15
 $6
 $4
$(28)
$(44)
$8

$2

$4
 $11

$8
 $2
 $1
_________
(a)Includes investmentRealized income includes interest, dividends and realized gains and losses on sales of investments of the trust funds.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 NDT fund activitydecommissioning-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 20172018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
The following utility taxes are included in revenues and expenses for the three and six months ended June 30, 2018March 31, 2019 and 2017.2018. 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 onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
 Three Months Ended June 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$218

$29

$60

$30

$21
 $78
 $73

$5

$—
 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

$—
 Six Months Ended June 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$452

$60

$121

$63

$47
 $161
 $151

$10

$—
 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
 Three Months Ended June 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$213

$30

$57

$29

$21
 $76
 $72

$4

$—
The following tables provide additional information regarding the 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)

 Six Months Ended June 30, 2017
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes$438

$63

$116

$60

$47
 $152
 $143

$9

$—
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017.
 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
 Six Months Ended June 30, 2018
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization and accretion                 
Property, plant and equipment(a)
$1,873
 $890
 $406
 $135
 $164
 $236
 $107
 $64
 $47
Amortization of regulatory assets(a)
278
 —
 53
 14
 84
 127
 81
 24
 22
Amortization of intangible assets, net(a)
28
 24
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
10
 10
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
569
 569
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
242
 242
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$3,000

$1,735

$459

$149

$248
 $363
 $188

$88

$69
Six Months Ended June 30, 2017Three Months Ended March 31, 2018
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization and accretion                                  
Property, plant and equipment(a)
$1,545
 $612
 $384
 $129
 $155
 $227
 $101
 $61
 $44
$926
 $436
 $201
 $68
 $82
 $117
 $53
 $32
 $23
Amortization of regulatory assets(a)
238
 —
 35
 12
 84
 105
 59
 18
 28
152
 —
 27
 7
 52
 66
 43
 13
 10
Amortization of intangible assets, net(a)
28
 25
 —
 —
 —
 —
 —
 —
 —
13
 12
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
20
 20
 —
 —
 —
 —
 —
 —
 —
3
 3
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
529
 529
 —
 —
 —
 —
 —
 —
 —
287
 287
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
231
 229
 —
 —
 —
 —
 —
 —
 —
120
 120
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$2,591

$1,415

$419

$141

$239
 $332
 $160

$79

$72
$1,501

$858

$228

$75

$134
 $183
 $96

$45

$33
_________
(a)Included in Depreciation and amortization onin the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(b)Included in Operating revenues or Purchased power and fuel expense onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Purchased power and fuel expense onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(d)Included in Operating and maintenance expense onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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

Six Months Ended June 30, 2018Three Months Ended March 31, 2019
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:                                  
Pension and non-pension postretirement benefit costs$290
 $100
 $88
 $10
 $29
 $34
 $8
 $3
 $6
$106
 $31
 $24
 $2
 $15
 $23
 $6
 $4
 $4
Loss from equity method investments12
 12
 —
 —
 —
 —
 —
 —
 —
6
 6
 —
 —
 —
 —
 —
 —
 —
Provision for uncollectible accounts77
 28
 18
 11
 5
 15
 7
 2
 5
43
 —
 9
 16
 8
 10
 4
 4
 2
Stock-based compensation costs47
 —
 —
 —
 —
 —
 —
 —
 —
28
 —
 —
 —
 —
 —
 —
 —
 —
Other decommissioning-related activity(a)
(61) (61) —
 —
 —
 —
 —
 —
 —
(202) (202) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
(7) (7) —
 —
 —
 —
 —
 —
 —
37
 37
 —
 —
 —
 —
 —
 —
 —
Amortization of regulatory asset related to debt costs4
 —
 2
 —
 —
 2
 1
 1
 —
3
 —
 —
 —
 —
 1
 —
 —
 —
Amortization of rate stabilization deferral13
 —
 —
 —
 —
 13
 10
 3
 —
(6) —
 —
 —
 —
 (6) (7) 1
 —
Amortization of debt fair value adjustment(7) (6) —
 —
 —
 (1) —
 —
 —
(4) (3) —
 —
 —
 (1) —
 —
 —
Discrete impacts from EIMA and FEJA(c)
14
 —
 14
 —
 —
 —
 —
 —
 —
28
 —
 28
 —
 —
 —
 —
 —
 —
Amortization of debt costs18
 7
 2
 1
 1
 3
 1
 —
 —
9
 3
 1
 —
 —
 1
 1
 —
 —
Provision for excess and obsolete inventory13
 12
 1
 —
 —
 —
 —
 —
 —
Long-term incentive plan51
 —
 —
 —
 —
 —
 —
 —
 —
25
 —
 —
 —
 —
 —
 —
 —
 —
Amortization of operating ROU asset53
 34
 1
 —
 8
 9
 2
 2
 1
Other15
 —
 (8) —
 (8) 5
 (3) 5
 1
1
 4
 (7) (2) (4) (2) (3) —
 (2)
Total other non-cash operating activities$479

$85

$117

$22

$27
 $71
 $24

$14

$12
$127

$(90)
$56

$16

$27
 $35
 $3

$11

$5
Non-cash investing and financing activities:Non-cash investing and financing activities:                               
(Decrease) increase in capital expenditures not paid$(283) $(310) $(22) $(17) $10
 $61
 $28
 $17
 $14
Increase in PPE related to ARO update47
 47
 —
 —
 —
 —
 —
 —
 —
Change in capital expenditures not paid$(229) $(93) $(80) $8
 $2
 $(55) $(15) $(17) $(24)
Change in PPE related to ARO update301
 301
 —
 —
 —
 —
 —
 —
 —
Dividends on stock compensation3
 —
 —
 —
 —
 —
 —

—
 —
1
 —
 —
 —
 —
 —
 —

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

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

Six Months Ended June 30, 2017Three Months Ended March 31, 2018
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACEExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:                                  
Pension and non-pension postretirement benefit costs$320
 $113
 $87
 $14
 $31
 $48
 $13
 $6
 $7
$145
 $51
 $45
 $5
 $14
 $15
 $4
 $—
 $3
Loss from equity method investments19
 19
 —
 —
 —
 —
 —
 —
 —
7
 7
 —
 —
 —
 —
 —
 —
 —
Provision for uncollectible accounts52
 19
 15
 9
 3
 6
 4
 —
 2
64
 11
 8
 17
 8
 20
 6
 8
 5
Stock-based compensation costs57
 —
 —
 —
 —
 —
 —
 —
 —
29
 —
 —
 —
 —
 —
 —
 —
 —
Other decommissioning-related activity(a)
(144) (144) —
 —
 —
 —
 —
 —
 —
(31) (31) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
11
 11
 —
 —
 —
 —
 —
 —
 —
(7) (7) —
 —
 —
 —
 —
 —
 —
Amortization of regulatory asset related to debt costs4
 —
 2
 —
 —
 2
 1
 1
 —
2
 —
 1
 —
 —
 1
 —
 —
 —
Amortization of rate stabilization deferral(8) —
 —
 —
 7
 (15) (10) (5) —
7
 —
 —
 —
 —
 7
 1
 6
 —
Amortization of debt fair value adjustment(9) (6) —
 —
 —
 (3) —
 —
 —
(3) (3) —
 —
 —
 —
 —
 —
 —
Discrete impacts from EIMA and FEJA (c)
(51) —
 (51) —
 —
 —
 —
 —
 —
(4) —
 (4) —
 —
 —
 —
 —
 —
Amortization of debt costs49
 30
 2
 1
 1
 —
 —
 —
 —
9
 3
 1
 —
 —
 1
 —
 —
 —
Provision for excess and obsolete inventory51
 49
 1
 —
 —
 1
 —
 —
 —
13
 12
 1
 —
 —
 —
 —
 —
 —
Merger-related commitments(d)
—
 —
 —
 —
 —
 (8) (6) (2) —
Severance costs25
 17
 —
 —
 —
 3
 —
 —
 —
Other39
 13
 2
 (2) (7) (6) (2) (3) (2)9
 2
 (6) (1) (2) 9
 (1) 5
 1
Total other non-cash operating activities$415

$121

$58

$22

$35
 $28
 $—

$(3)
$7
$240

$45

$46

$21

$20
 $53
 $10

$19

$9
Non-cash investing and financing activities:                                  
(Decrease) increase in capital expenditures not paid$(105) $48
 $(82) $(44) $6
 $(8) $—
 $15
 $(14)
Fair value of pension obligation transferred in connection with the FitzPatrick acquisition—
 49
 —
 —
 —
 —
 —
 —
 —
Change in capital expenditures not paid$(177) $(131) $(48) $(25) $(11) $61
 $19
 $14
 $27
Change in PPE related to ARO update103
 103
 —
 —
 —
 —
 —
 —
 —
32
 32
 —
 —
 —
 —
 —
 —
 —
Indemnification of like-kind exchange tax position(e)
—
 —
 23
 —
 —
 —
 —
 —
 —
Non-cash financing of capital projects13
 13
 —
 —
 —
 —
 —
 —
 —
Dividends on stock compensation3
 —
 —
 —
 —
 —
 —
 —
 —
1
 —
 —
 —
 —
 —
 —
 —
 —
Loss on reissuance of treasury stock1,054
 —
 —
 —
 —
 —
 —
 —
 —
_________
(a)Includes the elimination of NDT funddecommissioning-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 20172018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded in Operating revenues and expenses.
(c)Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 6 — Regulatory Matters for additional information.
(d)
See Note 4 - Mergers, Acquisitions and Dispositions for additional information.
(e)See Note 12 - Income Taxes for discussion of the like-kind exchange tax position.

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

The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
June 30, 2018Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$694
 $420
 $30
 $18
 $7
 $195
 $47
 $141
 $6
Restricted cash206
 130
 5
 5
 1
 38
 33
 —
 5
Restricted cash included in other long-term assets128
 —
 108
 —
 —
 20
 —
 —
 20
Total cash, cash equivalents and restricted cash$1,028
 $550
 $143
 $23
 $8
 $253
 $80
 $141
 $31
December 31, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$898
 $416
 $76
 $271
 $17
 $30
 $5
 $2
 $2
Restricted cash207
 138
 5
 4
 1
 42
 35
 —
 6
Restricted cash included in other long-term assets85
 —
 63
 —
 —
 23
 —
 —
 23
Total cash, cash equivalents and restricted cash$1,190
 $554
 $144
 $275
 $18
 $95
 $40
 $2
 $31
June 30, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$536
 $265
 $39
 $45
 $12
 $151
 $119
 $6
 $7
Restricted cash252
 166
 12
 4
 6
 40
 34
 —
 7
Restricted cash included in other long-term assets23
 —
 —
 —
 —
 23
 —
 —
 23
Total cash, cash equivalents and restricted cash$811
 $431
 $51
 $49
 $18
 $214
 $153
 $6
 $37
December 31, 2016Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$635
 $290
 $56
 $63
 $23
 $170
 $9
 $46
 $101
Restricted cash253
 158
 2
 4
 24
 43
 33
 —
 9
Restricted cash included in other long-term assets26
 —
 —
 —
 3
 23
 —
 —
 23
Total cash, cash equivalents and restricted cash$914
 $448
 $58
 $67
 $50
 $236
 $42
 $46
 $133
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K. 
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants as of June 30, 2018 and December 31, 2017.
June 30, 2018Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:                 
Accumulated depreciation and amortization$22,302
(a) 
$12,143
(a)  
$4,491

$3,482

$3,530
 $671
 $3,269

$1,295

$1,105
Accounts receivable:                 
Allowance for uncollectible accounts$339

$123

$82

$57

$21
 $55
 $23

$14

$18
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, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:                 
Accumulated depreciation and amortization$21,064
(b) 
$11,428
(b) 
$4,269

$3,411

$3,405
 $487
 $3,177

$1,247

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

$114

$73

$56

$24
 $55
 $21

$16

$18
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
December 31, 2017Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Cash and cash equivalents$898
 $416
 $76
 $271
 $17
 $30
 $5
 $2
 $2
Restricted cash207
 138
 5
 4
 1
 42
 35
 —
 6
Restricted cash included in other long-term assets85
 —
 63
 —
 —
 23
 —
 —
 23
Total cash, cash equivalents and restricted cash$1,190
 $554
 $144
 $275
 $18
 $95
 $40
 $2
 $31
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 liabilities of the Registrants as of March 31, 2019 and December 31, 2018.
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 $3,094$3,040 million.
(b)Includes accumulated amortization of nuclear fuel in the reactor core of $3,159$2,969 million.

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

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 Installment Plan Receivables (Exelon and PECO)
PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restoreACE 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 service, as required byPOR programs. Purchased billed receivables are recorded on a net basis in Exelon’s and the PAPUC. Customers with past due balances that meet certain income criteriaUtility Registrant's Consolidated Statements of Operations and Comprehensive Income and are provided the option to enter into an installment payment plan, some of which have terms greater than one year. The receivable balance for these payment agreement receivables is recordedclassified in Other accounts receivable, fornet in their Consolidated Balance Sheets. The following tables provide information about the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $11 millionpurchased receivables of those companies as of June 30, 2018March 31, 2019 and December 31, 2017. The allowance for uncollectible accounts balance associated with these receivables at June 30, 2018 of $12 million consists of $4 million and $8 million for medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2017 of $11 million consists of $3 million and $8 million for medium risk and high risk segments, respectively. See Note 1 — Significant Accounting Policies of the Exelon 2017 Form 10-K for additional information regarding uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables.2018.
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, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through a rate rider. BGE, Pepco and DPL recover actual write-offs which are reflected in the POR discount rate.
19.18. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM)CODM in deciding how to evaluate performance and allocate resources at each of the Registrants.
Exelon has twelveeleven reportable segments, which include ComEd, PECO, BGE, PHI's three reportable segments consisting of Pepco, DPL and ACE, and Generation’s sixGeneration's five reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”, which includes activities in the South, West and Canada.ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL and ACE. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income and return on equity.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 sixfive 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.
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)

Midwest represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.
New York represents operations within ISO-NY, which covers the state of New York in its entirety.
ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.
Other Power Regions:
South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.PJM.
West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado and parts of New Mexico, Wyoming and South Dakota.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 revenues net of purchased power and fuel expense (RNF).RNF. Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.
During the first quarter of 2019, due to a change in economics in our New England region, Generation 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 months ended March 31, 2019 and 2018 is as follows:
Three Months Ended March 31, 2019 and 2018
 
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

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

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and six months ended June 30, 2018 and 2017 is as follows:
Three Months Ended June 30, 2018 and 2017
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Operating revenues(c):
               
2018
Competitive businesses electric revenues$3,939
 $—
 —
 $—
 $—
 $—
 $(270) $3,669
$4,509
 $—
 $—
 $—
 $—
 $—
 $(391) $4,118
Competitive businesses natural gas revenues489
 —
 —
 —
 —
 —
 —
 489
955
 —
 —
 —
 —
 —
 (8) 947
Competitive businesses other revenues151
 —
 —
 —
 —
 —
 (4) 147
48
 —
 —
 —
 —
 —
 —
 48
Rate-regulated electric revenues—
 1,398
 560
 548
 1,045
 —
 (9) 3,542
—
 1,512
 634
 658
 1,169
 —
 (18) 3,955
Rate-regulated natural gas revenues—
 —
 93
 114
 28
 —
 (5) 230
—
 —
 232
 319
 78
 —
 (4) 625
Shared service and other revenues—
 —
 —
 —
 3
 487
 (491) (1)—
 —
 —
 —
 4
 451
 (455) —
Total operating revenues$4,579
 $1,398
 $653
 $662
 $1,076
 $487
 $(779) $8,076
$5,512
 $1,512
 $866
 $977
 $1,251
 $451
 $(876) $9,693
2017               
Competitive businesses electric revenues$3,759
 $—
 $—
 $—
 $—
 $—
 $(266) $3,493
Competitive businesses natural gas revenues430
 —
 —
 —
 —
 —
 —
 430
Competitive businesses other revenues27
 —
 —
 —
 —
 —
 —
 27
Rate-regulated electric revenues—
 1,357
 550
 571
 1,040
 —
 (7) 3,511
Rate-regulated natural gas revenues—
 —
 80
 103
 22
 —
 (1) 204
Shared service and other revenues—
 —
 —
 —
 12
 449
 (461) —
Total operating revenues$4,216
 $1,357
 $630
 $674
 $1,074
 $449
 $(735) $7,665
Intersegment revenues(d):
                              
2019$317
 $4
 $1
 $6
 $4
 $453
 $(785) $—
2018$273
 $5
 $2
 $6
 $3
 $487
 $(776) $—
400
 14
 2
 6
 4
 450
 (876) —
2017266
 3
 2
 3
 12
 448
 (734) —
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
2018$181
 $164
 $96
 $51
 $84
 $(34) $—
 $542
186
 165
 113
 128
 65
 (21) —
 636
2017(236) 118
 88
 45
 66
 13
 —
 94
Capital Expenditures               
2019$511
 $503
 $222
 $258
 $358
 $21
 $—
 $1,873
2018628
 531
 217
 224
 258
 22
 —
 1,880
Total assets:              
              
June 30, 2018$47,668
 $30,446
 $10,345
 $9,241
 $21,766
 $8,438
 $(10,655) $117,249
December 31, 201748,457
 29,726
 10,170
 9,104
 21,247
 8,618
 (10,552) 116,770
               
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

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

__________
(a)Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $45 million, sales to BGE of $76 million, sales to Pepco of $70 million, sales to DPL of $23 million and sales to ACE of $8 million in the Mid-Atlantic region, and sales to ComEd of $94 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for the three months ended June 30,Generation in 2018 include revenue from sales to PECO of $25$37 million, sales to BGE of $63$65 million, sales to Pepco of $46$52 million, sales to DPL of $30$46 million and sales to ACE of $6 million in the Mid-Atlantic region, and sales to ComEd of $103 million in the Midwest region, which eliminate upon consolidation. For the three months ended June 30, 2017, intersegment revenues for Generation include revenue from sales to PECO of $34 million, sales to BGE of $99 million, sales to Pepco of $68 million, sales to DPL of $40 million and sales to ACE of $7 million in the Mid-Atlantic region, and sales to ComEd of $18$194 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 onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 1817 — Supplemental Financial Information for additional information on total utility taxes for the three months ended June 30, 2018 and 2017.taxes.
(d)Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

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

PHI:
Pepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHIPepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHI
Operating revenues(a):
Operating revenues(a):
Operating revenues(a):
Three Months Ended June 30, 2018           
2019           
Rate-regulated electric revenues$523
 $261
 $265
 $—
 $(4) $1,045
$575
 $310
 $273
 $—
 $(5) $1,153
Rate-regulated natural gas revenues—
 28
 —
 —
 —
 28
—
 70
 —
 —
 1
 71
Shared service and other revenues—
 —
 —
 108
 (105) 3
—
 —
 —
 106
 (102) 4
Total operating revenues$523
 $289
 $265
 $108
 $(109) $1,076
$575
 $380
 $273
 $106
 $(106) $1,228
Three Months Ended June 30, 2017           
2018           
Rate-regulated electric revenues$514
 $260
 $270
 $—
 $(4) $1,040
$557
 $306
 $310
 $—
 $(4) $1,169
Rate-regulated natural gas revenues—
 22
 —
 —
 —
 22
—
 78
 —
 —
 —
 78
Shared service and other revenues—
 —
 —
 13
 (1) 12
—
 —
 —
 113
 (109) 4
Total operating revenues$514
 $282
 $270
 $13
 $(5) $1,074
$557
 $384
 $310
 $113
 $(113) $1,251
Intersegment revenues:                      
Three Months Ended June 30, 2018$2
 $2
 $1
 $107
 $(109) $3
Three Months Ended June 30, 20171
 2
 1
 13
 (5) 12
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):                      
Three Months Ended June 30, 2018$54
 $26
 $8
 $(7) $3
 $84
Three Months Ended June 30, 201743
 19
 8
 (16) 12
 66
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:                      
June 30, 2018$8,123
 $4,562
 $3,619
 $10,713
 $(5,251) $21,766
December 31, 20177,832
 4,357
 3,445
 10,600
 (4,987) 21,247
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 onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 1817 — Supplemental Financial Information for additional information on total utility taxes for the three months ended June 30, 2018 and 2017.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 three months ended June 30, 2018 and 2017.

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

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.

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

Competitive Business Revenues (Generation):
Three Months Ended June 30, 2018Three Months Ended March 31, 2019
Revenues from external parties(a)
 Intersegment
revenues
Total
Revenues
Revenues from external parties(a)
 Intersegment
revenues
Total
Revenues
Contracts with customers 
Other(b)
 Total Contracts with customers 
Other(b)
 Total 
Mid-Atlantic$1,220
 $58
 $1,278
 $4
 $1,282
$1,286
 $(24) $1,262
 $(6) $1,256
Midwest1,062
 73
 1,135
 (5) 1,130
1,055
 59
 1,114
 (6) 1,108
New England551
 (14) 537
 (3) 534
New York392
 (2) 390
 2
 392
409
 (16) 393
 —
 393
ERCOT165
 111
 276
 1
 277
130
 79
 209
 3
 212
Other Power Regions210
 113
 323
 (36) 287
1,165
 194
 1,359
 (6) 1,353
Total Competitive Businesses Electric Revenues3,600
 339
 3,939
 (37) 3,902
4,045
 292
 4,337
 (15) 4,322
Competitive Businesses Natural Gas Revenues295
 194
 489
 37
 526
584
 295
 879
 15
 894
Competitive Businesses Other Revenues(c)
125
 26
 151
 —
 151
120
 (40) 80
 —
 80
Total Generation Consolidated Operating Revenues$4,020
 $559
 $4,579
 $—
 $4,579
$4,749
 $547
 $5,296
 $—
 $5,296
Three Months Ended June 30, 2017Three Months Ended March 31, 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$1,368
 $(12) $1,356
 $9
 $1,365
$1,355
 $80
 $1,435
 $5
 $1,440
Midwest986
 72
 1,058
 (8) 1,050
1,273
 71
 1,344
 2
 1,346
New England462
 (24) 438
 (5) 433
New York405
 (13) 392
 (5) 387
439
 (29) 410
 (1) 409
ERCOT186
 61
 247
 —
 247
149
 59
 208
 1
 209
Other Power Regions142
 126
 268
 (9) 259
935
 177
 1,112
 (32) 1,080
Total Competitive Businesses Electric Revenues3,549
 210
 3,759
 (18) 3,741
4,151
 358
 4,509
 (25) 4,484
Competitive Businesses Natural Gas Revenues244
 186
 430
 19
 449
522
 433
 955
 25
 980
Competitive Businesses Other Revenues(c)
179
 (152) 27
 (1) 26
134
 (86) 48
 —
 48
Total Generation Consolidated Operating Revenues$3,972
 $244
 $4,216
 $—
 $4,216
$4,807
 $705
 $5,512
 $—
 $5,512
__________
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $15 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the three months ended June 30, 2017, unrealized mark-to-market losses of $5$52 million and $143$98 million for the three months ended June 30,in 2019 and 2018, and 2017, respectively, and elimination of intersegment revenues.

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

Revenues net of purchased power and fuel expense (Generation):
Three Months Ended June 30, 2018 Three Months Ended June 30, 2017Three Months Ended March 31, 2019 Three Months Ended March 31, 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$722
 $13
 $735
 $757
 $26
 $783
$679
 $4
 $683
 $836
 $14
 $850
Midwest770
 2
 772
 728
 —
 728
769
 2
 771
 847
 13
 860
New England104
 (8) 96
 157
 (10) 147
New York259
 7
 266
 270
 —
 270
262
 3
 265
 282
 1
 283
ERCOT129
 (47) 82
 121
 (51) 70
98
 (24) 74
 106
 (70) 36
Other Power Regions125
 (35) 90
 134
 (44) 90
174
 (18) 156
 279
 (43) 236
Total Revenues net of purchased power and fuel for Reportable Segments2,109

(68)
2,041

2,167

(79)
2,088
1,982

(33)
1,949

2,350

(85)
2,265
Other(b)
190
 68
 258
 (108) 79
 (29)109
 33
 142
 (131) 85
 (46)
Total Generation Revenues net of purchased power and fuel expense$2,299

$—

$2,299

$2,059

$—

$2,059
$2,091

$—

$2,091

$2,219

$—

$2,219
__________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $20 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the three months ended June 30, 2017, unrealized mark-to-market gainslosses of $90$28 million and losses of $184$266 million for the three months ended June 30,in 2019 and 2018, and 2017, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 -— Early Plant Retirements of $20$5 million decrease and $2$15 million decrease to revenue net of purchased powerRNF in 2019 and fuel expense for the three months ended June 30, 2018, and 2017, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.RNF.

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

Electric and Gas Revenue by Customer Class (ComEd, PECO, BGE, PHI, PECO, DPL and ACE)(Utility Registrants):
Three Months Ended June 30, 2018Three Months Ended March 31, 2019
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACEComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues                          
Residential$699
 $338
 $295
 $505
 $228
 $142
 $135
$710
 $409
 $385
 $579
 $256
 $185
 $138
Small commercial & industrial357
 97
 60
 115
 33
 44
 38
360
 96
 70
 120
 38
 48
 34
Large commercial & industrial127
 52
 101
 282
 212
 25
 45
132
 48
 110
 267
 204
 24
 39
Public authorities & electric railroads12
 6
 7
 16
 9
 3
 4
13
 7
 7
 14
 8
 3
 3
Other(a)
213
 60
 78
 133
 49
 41
 44
217
 62
 80
 157
 53
 47
 57
Total rate-regulated electric revenues(b)
1,408
 553
 541
 1,051
 531
 255
 266
$1,432
 $622
 $652
 $1,137
 $559
 $307
 $271
Rate-regulated natural gas revenues                          
Residential—
 62
 74
 13
 —
 13
 —
$—
 $198
 $219
 $44
 $—
 $44
 $—
Small commercial & industrial—
 25
 13
 8
 —
 8
 —
—
 72
 35
 19
 —
 19
 —
Large commercial & industrial—
 —
 23
 1
 —
 1
 —
—
 1
 50
 1
 —
 1
 —
Transportation—
 5
 —
 4
 —
 4
 —
—
 7
 —
 4
 —
 4
 —
Other(c)
—
 1
 12
 2
 —
 2
 —
—
 2
 4
 3
 —
 3
 —
Total rate-regulated natural gas revenues(d)
—
 93
 122
 28
 —
 28
 —
$—
 $280
 $308
 $71
 $—
 $71
 $—
Total rate-regulated revenues from contracts with customers1,408
 646
 663
 1,079
 531
 283
 266
$1,432
 $902
 $960
 $1,208
 $559
 $378
 $271
                          
Other revenues                          
Revenues from alternative revenue programs(17) 2
 (4) (7) (10) 4
 (1)$(28) $(3) $10
 $15
 $14
 $—
 $1
Other rate-regulated electric revenues(e)
7
 5
 3
 4
 2
 2
 —
4
 1
 3
 4
 2
 1
 1
Other rate-regulated natural gas revenues(e)
—
 —
 —
 —
 —
 —
 —
—
 —
 3
 1
 —
 1
 —
Total other revenues(10) 7
 (1) (3) (8) 6
 (1)$(24) $(2) $16
 $20
 $16
 $2
 $2
Total rate-regulated revenues for reportable segments$1,398
 $653
 $662
 $1,076
 $523
 $289
 $265
$1,408
 $900
 $976
 $1,228
 $575
 $380
 $273

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

Three Months Ended June 30, 2017Three Months Ended March 31, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACEComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues                          
Residential$644
 $331
 $300
 $498
 $223
 $145
 $130
$717
 $403
 $393
 $610
 $259
 $191
 $160
Small commercial & industrial340
 100
 58
 119
 34
 45
 40
385
 101
 68
 115
 32
 46
 37
Large commercial & industrial119
 57
 107
 268
 193
 26
 49
152
 58
 106
 259
 190
 23
 46
Public authorities & electric railroads11
 8
 8
 16
 8
 4
 4
14
 8
 7
 14
 7
 4
 3
Other(a)
217
 51
 71
 129
 49
 39
 44
230
 62
 78
 156
 49
 41
 66
Total rate-regulated electric revenues(b)
1,331
 547
 544
 1,030
 507
 259
 267
$1,498
 $632
 $652
 $1,154
 $537
 $305
 $312
Rate-regulated natural gas revenues                          
Residential—
 50
 60
 10
 —
 10
 —
$—
 $161
 $224
 $47
 $—
 $47
 $—
Small commercial & industrial—
 22
 12
 5
 —
 5
 —
—
 62
 34
 18
 —
 18
 —
Large commercial & industrial—
 —
 19
 2
 —
 2
 —
—
 1
 47
 4
 —
 4
 —
Transportation—
 5
 —
 2
 —
 2
 —
—
 6
 —
 5
 —
 5
 —
Other(c)
—
 3
 4
 3
 —
 3
 —
—
 2
 27
 4
 —
 4
 —
Total rate-regulated natural gas revenues(d)
—
 80
 95
 22
 —
 22
 —
$—
 $232
 $332
 $78
 $—
 $78
 $—
Total rate-regulated revenues from contracts with customers1,331
 627
 639
 1,052
 507
 281
 267
$1,498
 $864
 $984
 $1,232
 $537
 $383
 $312
                          
Other revenues                          
Revenues from alternative revenue programs18
 —
 32
 8
 5
 —
 3
$5
 $(1) $(13) $18
 $19
 $1
 $(2)
Other rate-regulated electric revenues(e)
8
 3
 2
 3
 2
 1
 —
9
 3
 4
 1
 1
 —
 —
Other rate-regulated natural gas revenues(e)
—
 —
 1
 —
 —
 —
 —
—
 —
 2
 —
 —
 —
 —
Other revenues(f)
—
 —
 —
 11
 —
 —
 —
Total other revenues26
 3
 35
 22
 7
 1
 3
$14
 $2
 $(7) $19
 $20
 $1
 $(2)
Total rate-regulated revenues for reportable segments$1,357
 $630
 $674
 $1,074
 $514
 $282
 $270
$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 $5$4 million, $2$1 million, $2 million, $3 million, $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the three months ended June 30, 2018in 2019 and $3$14 million, $2 million, $1$2 million, $1$4 million $1$2 million, $2 million and $11 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the three months ended June 30, 2017.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, for the three months ended June 30, 2018in 2019 and less than $1 million and $2 million at PECO and BGE, respectively, for the three months ended June 30, 2017.2018.
(e)Includes late payment charge revenues.
(f)Includes operating revenues from affiliates of $11 million at PHI for the three months ended June 30, 2017.

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

Six Months Ended June 30, 2018 and 2017
 
Generation(a)
 ComEd PECO BGE PHI 
Other(b)
 Intersegment
Eliminations		 Exelon
Operating revenues(c):
2018               
Competitive businesses electric revenues$8,448
 $—
 $—
 $—
 $—
 $—
 $(663) $7,785
Competitive businesses natural gas revenues1,444
 —
 —
 —
 —
 —
 (8) 1,436
Competitive businesses other revenues198
 —
 —
 —
 —
 —
 (2) 196
Rate-regulated electric revenues—
 2,910
 1,193
 1,206
 2,214
 —
 (27) 7,496
Rate-regulated natural gas revenues—
 —
 325
 433
 106
 —
 (9) 855
Shared service and other revenues—
 —
 —
 —
 7
 940
 (946) 1
Total operating revenues$10,090
 $2,910
 $1,518
 $1,639
 $2,327
 $940
 $(1,655) $17,769
2017               
Competitive businesses electric revenues$7,467
 $—
 $—
 $—
 $—
 $—
 $(592) $6,875
Competitive businesses natural gas revenues1,348
 —
 —
 —
 —
 —
 —
 1,348
Competitive businesses other revenues278
 —
 —
 —
 —
 —
 (1) 277
Rate-regulated electric revenues—
 2,656
 1,140
 1,237
 2,138
 1
 (16) 7,156
Rate-regulated natural gas revenues—
 —
 286
 388
 87
 —
 (4) 757
Shared service and other revenues—
 —
 —
 —
 23
 870
 (893) —
Total operating revenues$9,093
 $2,656
 $1,426
 $1,625
 $2,248
 $871
 $(1,506) $16,413
Intersegment revenues(d):
               
2018$672
 $19
 $3
 $12
 $7
 $937
 $(1,650) $—
2017594
 9
 3
 8
 23
 866
 (1,503) —
Net income (loss):               
2018$368
 $329
 $210
 $179
 $149
 $(56) $—
 $1,179
2017164
 259
 215
 169
 205
 54
 —
 1,066

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

__________
(a)Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the six months ended June 30, 2018 include revenue from sales to PECO of $61 million, sales to BGE of $128 million, sales to Pepco of $98 million, sales to DPL of $76 million and sales to ACE of $12 million in the Mid-Atlantic region, and sales to ComEd of $297 million in the Midwest region, which eliminate upon consolidation. For the six months ended June 30, 2017, intersegment revenues for Generation include revenue from sales to PECO of $79 million, sales to BGE of $233 million, sales to Pepco of $152 million, sales to DPL of $91 million and sales to ACE of $16 million in the Mid-Atlantic region, and sales to ComEd of $23 million in the Midwest region, which eliminate upon consolidation.
(b)Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(c)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for total utility taxes for the six months ended June 30, 2018 and 2017.
(d)Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
PHI:
 Pepco DPL ACE 
Other(b)
 Intersegment
Eliminations		 PHI
Operating revenues(a):
           
Six Months Ended June 30, 2018           
Rate-regulated electric revenues$1,080
 $567
 $575
 $—
 $(8) $2,214
Rate-regulated natural gas revenues—
 106
 —
 —
 —
 106
Shared service and other revenues—
 —
 —
 221
 (214) 7
Total operating revenues$1,080
 $673
 $575
 $221
 $(222) $2,327
Six Months Ended June 30, 2017           
Rate-regulated electric revenues$1,045
 $557
 $544
 $1
 $(9) $2,138
Rate-regulated natural gas revenues—
 87
 —
 —
 —
 87
Shared service and other revenues—
 —
 —
 25
 (2) 23
Total operating revenues$1,045
 $644
 $544
 $26
 $(11) $2,248
Intersegment revenues:           
Six Months Ended June 30, 2018$3
 $4
 $2
 $220
 $(222) $7
Six Months Ended June 30, 20173
 4
 1
 24
 (9) 23
Net income (loss):           
Six Months Ended June 30, 2018$85
 $57
 $15
 $(15) $7
 $149
Six Months Ended June 30, 2017101
 76
 36
 (31) 23
 205
__________
(a)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for total utility taxes for the six months ended June 30, 2018 and 2017.
(b)Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors for six months ended June 30, 2018 and 2017. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants but exclude any intercompany revenues.

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

Competitive Business Revenues (Generation):
 Six Months Ended June 30, 2018
 
Revenues from external parties(a)
 
Intersegment
Revenues
 
Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$2,574
 $138
 $2,712
 $10
 $2,722
Midwest2,336
 143
 2,479
 (4) 2,475
New England1,276
 54
 1,330
 (4) 1,326
New York831
 (31) 800
 1
 801
ERCOT315
 169
 484
 2
 486
Other Power Regions420
 223
 643
 (67) 576
Total Competitive Businesses Electric Revenues7,752
 696
 8,448
 (62) 8,386
Competitive Businesses Natural Gas Revenues816
 628
 1,444
 62
 1,506
Competitive Businesses Other Revenues(c)
258
 (60) 198
 —
 198
Total Generation Consolidated Operating Revenues$8,826
 $1,264
 $10,090
 $—
 $10,090
 Six Months Ended June 30, 2017
 
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$2,862
 $(77) $2,785
 $5
 $2,790
Midwest1,964
 143
 2,107
 (5) 2,102
New England1,051
 (64) 987
 (7) 980
New York708
 (16) 692
 (8) 684
ERCOT354
 85
 439
 (1) 438
Other Power Regions270
 187
 457
 (14) 443
Total Competitive Businesses Electric Revenues7,209
 258
 7,467
 (30) 7,437
Competitive Businesses Natural Gas Revenues1,012
 336
 1,348
 31
 1,379
Competitive Businesses Other Revenues(c)
386
 (108) 278
 (1) 277
Total Generation Consolidated Operating Revenues$8,607
 $486
 $9,093
 $—
 $9,093
__________
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $17 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the six months ended June 30, 2017, unrealized mark-to-market losses of $102 million and $98 million for the six months ended June 30, 2018 and 2017, respectively, and elimination of intersegment revenues.

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

Revenues net of purchased power and fuel expense (Generation):
 Six Months Ended June 30, 2018 Six Months Ended June 30, 2017
 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
Mid-Atlantic$1,558
 $28
 $1,586
 $1,513
 $44
 $1,557
Midwest1,617
 14
 1,631
 1,431
 12
 1,443
New England227
 (11) 216
 271
 (14) 257
New York541
 8
 549
 415
 —
 415
ERCOT235
 (117) 118
 214
 (76) 138
Other Power Regions284
 (76) 208
 240
 (88) 152
Total Revenues net of purchased power and fuel expense for Reportable Segments4,462

(154)
4,308

4,084

(122)
3,962
Other(b)
55
 154
 209
 54
 122
 176
Total Generation Revenues net of purchased power and fuel expense$4,517

$—

$4,517

$4,138

$—

$4,138
__________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $22 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the six months ended June 30, 2017, unrealized mark-to-market losses of $175 million and $233 million for the six months ended June 30, 2018 and 2017, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 - Early Plant Retirements of $34 million decrease to revenue net of purchased power and fuel expense for the six months ended June 30, 2018, and the elimination of intersegment revenue net of purchased power and fuel expense.

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

Electric and Gas Revenue by Customer Class (ComEd, PECO, BGE, PHI, PECO, DPL and ACE):
 Six Months Ended June 30, 2018
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$1,416
 $741
 $688
 $1,114
 $486
 $333
 $295
Small commercial & industrial741
 198
 128
 230
 65
 90
 75
Large commercial & industrial280
 110
 207
 541
 402
 48
 91
Public authorities & electric railroads25
 14
 14
 30
 16
 7
 7
Other(a)
444
 122
 156
 289
 98
 82
 110
Total rate-regulated electric revenues(b)
2,906
 1,185
 1,193
 2,204
 1,067
 560
 578
Rate-regulated natural gas revenues             
Residential—
 223
 298
 60
 —
 60
 —
Small commercial & industrial—
 87
 47
 26
 —
 26
 —
Large commercial & industrial—
 1
 70
 5
 —
 5
 —
Transportation—
 11
 —
 9
 —
 9
 —
Other(c)
—
 3
 40
 6
 —
 6
 —
Total rate-regulated natural gas revenues(d)
—
 325
 455
 106
 —
 106
 —
Total rate-regulated revenues from contracts with customers2,906
 1,510
 1,648
 2,310
 1,067
 666
 578
              
Other revenues             
Revenues from alternative revenue programs(12) 1
 (17) 12
 10
 5
 (3)
Other rate-regulated electric revenues(e)
16
 7
 6
 5
 3
 2
 —
Other rate-regulated natural gas revenues(e)
—
 —
 2
 —
 —
 —
 —
Total other revenues4
 8
 (9) 17
 13
 7
 (3)
Total rate-regulated revenues for reportable segments$2,910
 $1,518
 $1,639
 $2,327
 $1,080
 $673
 $575

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

 Six Months Ended June 30, 2017
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$1,255
 $713
 $686
 $1,053
 $460
 $321
 $272
Small commercial & industrial668
 197
 128
 233
 68
 89
 76
Large commercial & industrial226
 109
 215
 526
 382
 50
 94
Public authorities & electric railroads22
 16
 15
 31
 16
 8
 7
Other(a)
437
 99
 138
 253
 96
 78
 86
Total rate-regulated electric revenues(b)
2,608
 1,134
 1,182
 2,096
 1,022
 546
 535
Rate-regulated natural gas revenues             
Residential—
 192
 245
 50
 —
 50
 —
Small commercial & industrial—
 77
 42
 22
 —
 22
 —
Large commercial & industrial—
 —
 64
 4
 —
 4
 —
Transportation—
 11
 —
 7
 —
 7
 —
Other(c)
—
 6
 17
 4
 —
 4
 —
Total rate-regulated natural gas revenues(d)
—
 286
 368
 87
 —
 87
 —
Total rate-regulated revenues from contracts with customers2,608
 1,420
 1,550
 2,183
 1,022
 633
 535
              
Other revenues             
Revenues from alternative revenue programs32
 —
 66
 38
 20
 9
 9
Other rate-regulated electric revenues(e)
16
 6
 7
 5
 3
 2
 —
Other rate-regulated natural gas revenues(e)
—
 —
 2
 —
 —
 —
 —
Other revenues(f)
—
 —
 —
 22
 —
 —
 —
Total other revenues48
 6
 75
 65
 23
 11
 9
Total rate-regulated revenues for reportable segments$2,656
 $1,426
 $1,625
 $2,248
 $1,045
 $644
 $544
__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $19 million, $3 million, $3 million, $7 million, $3 million, $4 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the six months ended June 30, 2018 and $9 million, $3 million, $3 million, $1 million, $3 million, $4 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the six months ended June 30, 2017.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of less than $1 million and $9 million at PECO and BGE, respectively, for the six months ended June 30, 2018 and less than $1 million and $5 million at PECO and BGE, respectively, for the six months ended June 30, 2017.
(e)Includes late payment charge revenues.
(f)Includes operating revenues from affiliates of $22 million at PHI for the six months ended June 30, 2017.

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

20.    Subsequent Events (Exelon and Generation)
Acquisition of FirstEnergy Solutions Load Business
On July 9, 2018, Generation entered into an Asset Purchase Agreement (the Purchase Agreement) with FirstEnergy Solutions Corporation (FirstEnergy). Pursuant to the Purchase Agreement, FirstEnergy assigns all of its retail electricity and wholesale load serving contracts and certain other related commodity contracts to Generation for an all cash purchase price of $140 million. Pursuant to the Purchase Agreement, Generation has agreed to use its commercially reasonable efforts to replace the guarantees and other credit support currently being provided by FirstEnergy in support of the ongoing competitive retail businesses and to reimburse FirstEnergy for any payments arising pursuant to such arrangements continuing for any post-closing period.
The transaction is expected to close in the fourth quarter of 2018. The closing of the transaction is subject to certain conditions, including Generation being the winning bidder after a court-supervised Section 363 bankruptcy auction, the approval of the Purchase Agreement by the United States Bankruptcy Court for the Northern District of Ohio following the auction, and expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Either party may terminate the Purchase Agreement if the transaction has not been consummated by December 31, 2018. The Purchase Agreement also includes various representations, warranties, covenants, indemnification and other provisions customary for a transaction of this nature.
Agreement for Sale and Decommissioning 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 the Oyster Creek Generating Station (Oyster Creek) located in Forked River, New Jersey. In February 2018, Generation announced that Oyster Creek would permanently shut down by October 2018, at the end of its current operating cycle. Generation is required to close Oyster Creek by December 2019, as part of an agreement with the State of New Jersey.
Under the terms of the transaction, Generation will transfer to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds valued at approximately $980 million as of June 30, 2018, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. In addition to the assumption of liability for the full decommissioning and ongoing management of spent fuel, other consideration to be received in the transaction is contingent on several factors, including a requirement that Generation deliver a minimum NDT fund balance at closing, subject to adjustment for specific terms that include income taxes that would be imposed on any net unrealized built-in gains and certain decommissioning activities to be performed during the pre-close period after the unit shuts down in the fall of 2018 and prior to the anticipated close of the transaction. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events.
As a result of the transaction, in the third quarter of 2018, Exelon and Generation will reclassify certain Oyster Creek assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. Exelon and Generation estimate a pre-tax charge to operating and maintenance expense ranging from $60 million to $100 million will be recognized in the third quarter of 2018 upon remeasurement of the Oyster Creek ARO.
Completion of the transaction contemplated by the sale agreement is subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory

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

approvals, and the receipt of a private letter ruling from the IRS. Generation currently anticipates satisfaction of the closing conditions to occur in the second half of 2019.

Table of Contents

Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations
(Dollars in millions except per share data, unless otherwise noted)
Exelon
Executive Overview
Exelon a utility services holding company, operates through the following principal subsidiaries:
Generation, whose integrated business consists of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services.
ComEd, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in northern Illinois, including the City of Chicago.
PECO, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision distribution services in the Pennsylvania counties surrounding the City of Philadelphia.
BGE, whose business consists of the purchase and regulated retail sale of electricity and natural gas and the provision of electricity distribution and transmission and gas distribution services in central Maryland, including the City of Baltimore.
Pepco, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission in the District of Columbia and major portions of Prince George's County and Montgomery County in Maryland.
DPL, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware.
ACE, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in southern New Jersey.
Pepco, DPL and ACE are operating companies of PHI, which is a utility services holding company engaged in the generation, delivery, and a wholly owned subsidiarymarketing of Exelon.energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.
Exelon has twelveeleven reportable segments consisting of Generation’s sixfive reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions in Generation)Regions), ComEd, PECO, BGE, Pepco, DPL and PHI's three utilityACE. During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation will disclose five reportable segments (Pepco, DPLconsisting of Mid-Atlantic, Midwest, New York, ERCOT and ACE).Other Power Regions. See Note 191 — 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 operating subsidiaries with a variety of corporate governance support services at cost, including corporate strategy and development, legal, human resources, financial, information technology finance, real estate, security, corporate communications and

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supply at cost. The costs of thesemanagement services. PHI also has a business services are directly charged or allocated to the applicable operating segments. The services are provided pursuant to service agreements. Additionally, the results of Exelon’s corporate operations include interest costs income from various investment and financing activities.
subsidiary, PHISCO, a wholly owned subsidiary of PHI,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 its operating subsidiaries. These servicesPHISCO are directly charged or allocated pursuant to service agreements among PHISCOthe applicable subsidiaries. Additionally, the results of Exelon’s corporate operations include interest costs and the participating operating subsidiaries.income from various investment and financing activities.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.

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Financial Results of Operations
GAAP Results of Operations
Operations. The following tables settable sets forth Exelon's GAAP consolidated results of operationsNet Income attributable to common shareholders by Registrant for the three and six months ended June 30, 2018March 31, 2019 compared to the same period in 2017. All amounts presented below are before the impact of income taxes, except as noted.
 Three Months Ended June 30, Favorable
(Unfavorable)
Variance
 2018 2017 
 Generation ComEd PECO BGE PHI Other Exelon Exelon 
Operating revenues$4,579
 $1,398
 $653
 $662
 $1,076
 $(292) $8,076
 $7,665
 $411
Purchased power and fuel2,280
 477
 222
 229
 381
 (274) 3,315
 3,086
 (229)
Revenue net of purchased power and fuel(a)
2,299
 921
 431
 433
 695
 (18) 4,761
 4,579
 182
Other operating expenses                 
Operating and maintenance1,418
 324
 191
 176
 255
 (57) 2,307
 2,945
 638
Depreciation and amortization466
 231
 74
 114
 180
 23
 1,088
 915
 (173)
Taxes other than income134
 79
 39
 59
 107
 10
 428
 420
 (8)
Total other operating expenses2,018
 634
 304
 349
 542
 (24) 3,823
 4,280
 457
Gain on sales of assets and businesses1
 1
 —
 1
 —
 1
 4
 1
 3
Operating income282
 288
 127
 85
 153
 7
 942
 300
 642
Other income and (deductions)                 
Interest expense, net(102) (85) (32) (25) (65) (64) (373) (436) 63
Other, net29
 4
 —
 4
 11
 (4) 44
 177
 (133)
Total other income and (deductions)(73) (81) (32) (21) (54) (68) (329) (259) (70)
Income (loss) before income taxes209
 207
 95
 64
 99
 (61) 613
 41
 572
Income taxes23
 43
 (1) 13
 15
 (27) 66
 (62) (128)
Equity in losses of unconsolidated affiliates(5) —
 —
 —
 —
 —
 (5) (9) 4
Net income (loss)181
 164
 96
 51
 84
 (34) 542
 94
 448
Net income (loss) attributable to noncontrolling interests3
 —
 —
 —
 —
 —
 3
 (1) (4)
Net income (loss) attributable to common shareholders$178
 $164
 $96
 $51
 $84
 $(34) $539
 $95
 $444

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 Six Months Ended June 30, 
Favorable
(Unfavorable)
Variance
 2018 2017 
 Generation ComEd PECO BGE PHI Other Exelon Exelon 
Operating revenues$10,090
 $2,910
 $1,518
 $1,639
 $2,327
 $(715) $17,769
 $16,413
 $1,356
Purchased power and fuel expense5,573
 1,082
 555
 609
 901
 (678) 8,042
 6,985
 (1,057)
Revenue net of purchased power and fuel expense(a)
4,517

1,828

963

1,030

1,426
 (37)
9,727

9,428
 299
Other operating expenses        

        
Operating and maintenance2,756
 638
 466
 397
 563
 (129) 4,691
 5,383
 692
Depreciation and amortization914
 459
 149
 248
 363
 46
 2,179
 1,811
 (368)
Taxes other than income272
 156
 79
 124
 221
 22
 874
 857
 (17)
Total other operating expenses3,942

1,253

694

769

1,147
 (61)
7,744

8,051
 307
Gain on sales of assets and businesses54
 5
 —
 1
 —
 —
 60
 5
 55
Bargain purchase gain—
 —
 —
 —
 —
 —
 —
 226
 (226)
Operating income629

580

269

262

279
 24

2,043

1,608
 435
Other income and (deductions)                 
Interest expense, net(202) (175) (64) (51) (128) (125) (745) (809) 64
Other, net(15) 12
 2
 9
 22
 (13) 17
 434
 (417)
Total other income and (deductions)(217)
(163)
(62)
(42)
(106) (138)
(728)
(375) (353)
Income (loss) before income taxes412
 417
 207
 220
 173
 (114) 1,315
 1,233
 82
Income taxes32
 88
 (3) 41
 24
 (57) 125
 149
 24
Equity in (losses) earnings of unconsolidated affiliates(12) —
 —
 —
 —
 1
 (11) (18) 7
Net income (loss)368

329

210

179

149

(56)
1,179

1,066
 113
Net income (loss) attributable to noncontrolling interests54
 —
 —
 —
 —
 —
 54
 (20) (74)
Net income (loss) attributable to common shareholders$314

$329

$210

$179

$149
 $(56)
$1,125

$1,086
 $39
_________
(a)The Registrants evaluate operating performance using the measure of revenues net of purchased power and fuel expense. The Registrants believe that revenues net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate their operational performance. Revenues net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017.Exelon’s Net income attributable to common shareholders was $539 million for the three months ended June 30, 2018 as compared to $95 million for the three months ended June 30, 2017, and diluted earnings per average common share were $0.56 for the three months ended June 30, 2018 as compared to $0.10for the three months ended June 30, 2017.

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Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $182 million for the three months ended June 30, 2018 compared to the same period in 2017 primarily due to the following factors:
Increase of $274 million at Generation due to mark-to-market gains of $90 million in 2018 compared to mark-to-market losses of $184 million in 2017;
Decrease of $34 million at Generation primarily due to lower realized energy prices partially offset by increased capacity prices, decreased nuclear outage days, the impact of Illinois ZES and impacts of Generation's natural gas portfolio;
Decrease of $37 million at ComEd primarily due to lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to FEJA; and
Decrease of $70 million in electric and gas revenues across all Utility Registrants, primarily reflecting lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates, partially offset by higher utility revenues due to regulatory rate increases at ComEd and PHI.
Operating and maintenance expense decreased by $638 million for the three months ended June 30, 2018 as compared to the same period in 2017 primarily due to the following factors:
Decrease of $379 million at Generation due to long-lived asset impairments primarily related to the EGTP assets held for sale in 2017, offset by long-lived asset impairments of certain merchant wind assets in West Texas in 2018;
Decrease of $69 million due to one-time charges related to Generation's decision to early retire the TMI nuclear facility in 2017;
Decrease of $64 million at Generation due to lower nuclear refueling outage costs;
Decrease of $60 million at Generation in labor, contracting and materials expense due to decreased spending related to energy efficiency projects and decreased costs related to the sale of Generation's electrical contracting business; and
Decrease of $37 million at ComEd primarily due to the change to defer and recover over time energy efficiency costs pursuant to FEJA.
Depreciation and amortization expense increased by $173 million for the three months ended June 30, 2018 as compared to the same period in 2017 primarily as a result of ongoing capital expenditures across all operating companies, accelerated depreciation and amortization due to Generation's decision to early retire the Oyster Creek and TMI nuclear facilities, increased amortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues), partially offset by certain regulatory assets that became fully amortized as of December 31, 2017 for BGE.
Taxes other than income remained relatively consistent for the three months ended June 30, 2018 compared to the same period in 2017.
Gain on sales of assets and businesses increased by $3 million for the three months ended June 30, 2018 compared to the same period in 2017 primarily due to a true up related to Generation's first quarter 2018 sale of its electrical contracting business.
Interest expense, net decreased by $63 million due to the retirement of long-term debt.

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Other, net decreased by $133 million primarily due to net unrealized and realized losses on NDT funds at Generation for the three months ended June 30, 2018 compared to net unrealized and realized gains on NDT funds for the same period in 2017.
Exelon’s effective income tax rates for the three months ended June 30, 2018 and 2017 were 10.8% and (151.2)%, respectively. The increase in the effective income tax rate for the three months ended June 30, 2018 compared to the same period in 2017 is primarily related to tax savings due to the lower federal income tax rate as a result of the TCJA at all Registrants, which is offset in Operating revenues at the Utility Registrants for the anticipated pass back of the tax savings through customer rates. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on TCJA's impact on regulatory proceedings.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017.Exelon’s Net income attributable to common shareholders was $1,125 million for the six months ended June 30, 2018 compared to $1,086 million for the six months ended June 30, 2017, and diluted earnings per average common share were $1.16 for the six months ended June 30, 2018 compared to $1.17for the six months ended June 30, 2017.
Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $299 million for the six months ended June 30, 2018 as compared to the same period in 2017. The year-over-year increase in Revenue net of purchased power and fuel expense was primarily due to the following factors:
Increase of $321 million at Generation primarily due to impact of the New York CES and Illinois ZES (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017), increased capacity prices, the acquisition of the FitzPatrick nuclear facility and decreased nuclear outage days, impacts of Generation's natural gas portfolio and the addition of two combined-cycle gas turbines in Texas, partially offset by the impact of the deconsolidation of EGTP in 2017, the conclusion of the Ginna Reliability Support Services Agreement and lower realized energy prices;
Increase of $58 million at Generation due to mark-to-market losses of $175 million in 2018 compared to $233 million in 2017;
Increase of $52 million at PECO, DPL and ACE primarily due to favorable weather conditions within their respective service territories;
Increase of $47 million due to higher mutual assistance revenues across all Utility Registrants, primarily at ComEd;
Decrease of $94 million at ComEd primarily due to lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to FEJA; and
Decrease of $156 million in electric and gas revenues across all Utility Registrants, primarily reflecting lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates, partially offset by higher utility revenues due to regulatory rate increases at ComEd, BGE and PHI.

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Operating and maintenance expense decreased by $692 million for the six months ended June 30, 2018 compared to the same period in 2017 primarily due to the following factors:
Decrease of $378 million at Generation due to long-lived asset impairments primarily related to the EGTP assets held for sale in 2017, offset by long-lived asset impairments of certain merchant wind assets in West Texas in 2018;
Decrease of $96 million at Generation due to lower nuclear refueling outage costs;
Decrease of $94 million at ComEd primarily due to the change to defer and recover over time energy efficiency costs pursuant to FEJA;
Decrease of $55 million at Generation due to lower merger-related costs;
Decrease of $42 million due to one-time charges related to Generation's decision to early retire the TMI nuclear facility in 2017, partially offset by one-time charges due to Generation's decision to early retire the Oyster Creek nuclear facility in 2018;
Decrease of $36 million related to a supplemental NEIL insurance distribution at Generation;
Increase of $81 million at PECO and BGE due to increased storm costs; and
Increase of $47 million due to higher mutual assistance expenses across all Utility Registrants, primarily at ComEd.
Depreciation and amortization expense increased by $368 million for the six months ended June 30, 2018 compared to the same period in 2017 primarily due to increased depreciation expense as a result of ongoing capital expenditures across all operating companies, accelerated depreciation and amortization due to Generation's decision to early retire the Oyster Creek and TMI nuclear facilities, increased amortization of Pepco's DC PLUG regulatory asset (an equal and offsetting amount has been reflected in Operating revenues), partially offset by certain regulatory assets that became fully amortized as of December 31, 2017 for BGE.
Taxes other than income increased due to increased gross receipts tax accruals at PECO and Pepco for the six months ended June 30, 2018 compared to the same period in 2017.
Gain on sales of assets and businesses increased by $55 million for the six months ended June 30, 2018 compared to the same period in 2017 primarily due to Generation's sale of its electrical contracting business.
Bargain purchase gain decreased by $226 million due to the gain associated with the FitzPatrick acquisition in first quarter 2017.
Interest expense, net decreased by $64 million due to the retirement of long-term debt.
Other, net decreased by $417 million primarily due to net unrealized and realized losses on NDT funds at Generation for the six months ended June 30, 2018 compared to net unrealized and realized gains on NDT funds for the same period in 2017.
Exelon’s effective income tax rates for the six months ended June 30, 2018 and 2017 were 9.5% and 12.1%, respectively. The decrease in the effective income tax rate for the six months ended June 30, 2018 compared to the same period in 2017 is primarily related to tax savings due to the lower federal income tax rate as a result of the TCJA at all Registrants, which is offset in Operating revenues at the Utility Registrants for the anticipated pass back of the tax savings through customer rates. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. See Note 6 — Regulatory Matters of the

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Combined Notes to Consolidated Financial Statements for additional information on TCJA's impact on regulatory proceedings.
2018. For additional information regarding the financial results for the three and six months ended June 30,March 31, 2019 and 2018 including explanation of the non-GAAP measure Revenue net of purchased power and fuel expense, see the discussions of Results of Operations by Registrant below.Registrant.
 Three Months Ended March 31, Favorable (unfavorable) variance
 2019 2018 
Exelon$907
 $585
 $322
Generation363
 136
 227
ComEd157
 165
 (8)
PECO168
 113
 55
BGE160
 128
 32
PHI117
 65
 52
Pepco55
 31
 24
DPL53
 31
 22
ACE10
 7
 3
Other(a)
(58) (22) (36)
__________
(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, 2019 Compared to Three Months Ended March 31, 2018.Net income attributable to common shareholders increased by $322 million and diluted earnings per average common share increased to $0.93 in 2019 from $0.60 in 2018 primarily due to:
Net unrealized gains on NDT funds in 2019 compared to losses in 2018;
Decreased mark-to-market losses;
A benefit associated with the remeasurement of the TMI ARO;
Increased capacity prices;
Regulatory rate increases at PECO, BGE, Pepco and DPL; and
Lower storms costs at PECO and BGE.
The increases were partially offset by:
Lower realized energy prices and
The absence of the revenue recognized in the first quarter 2018 related to ZECs generated in Illinois from June through December 2017.
Adjusted (non-GAAP) Operating EarningsEarnings.
Exelon’s adjusted (non-GAAP) operating earnings for the three months ended June 30, 2018 were $686 million, or $0.71 per diluted share, compared with adjusted (non-GAAP) operating earnings of $524 million, or $0.56 per diluted share for the same period in 2017. Exelon’s adjusted (non-GAAP) operating earnings for the six months ended June 30, 2018 were $1,611 million, or $1.66 per diluted share, compared with adjusted (non-GAAP) operating earnings of $1,124 million, or $1.21 per diluted share for the same period in 2017. In addition to net income, Exelon evaluates its operating performance using the measure of adjustedAdjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of period-over-periodyear-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.

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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 six months ended June 30, 2018March 31, 2019 compared to the same period in 2017.2018.
 Three Months Ended June 30,
 2018 2017
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$539
 $0.56
 $95
 $0.10
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $23 and $72, respectively)
(67) (0.07) 113
 0.12
Unrealized Losses (Gains) Related to NDT Fund Investments(b) (net of taxes of $77 and $20, respectively)
81
 0.08
 (45) (0.05)
Amortization of Commodity Contract Intangibles(c) (net of taxes of $0 and $8, respectively)
—
 —
 12
 0.01
Merger and Integration Costs(d) (net of taxes of $0 and $9, respectively)
1
 —
 15
 0.02
Long-Lived Asset Impairments(f) (net of taxes of $11 and $172, respectively)
30
 0.03
 268
 0.29
Plant Retirements and Divestitures(g) (net of taxes of $47 and $42, respectively)
127
 0.14
 66
 0.07
Cost Management Program(h) (net of taxes of $4 and $4, respectively)
12
 0.01
 6
 0.01
Change in Environmental Liabilities(j) (net of taxes of $2 and $0, respectively)
5
 0.01
 —
 —
Like-Kind Exchange Tax Position(k) (net of taxes of $0 and $66, respectively)
—
 —
 (26) (0.03)
Reassessment of Deferred Income Taxes(l) (entire amount represents tax expense)
(8) (0.01) —
 —
Noncontrolling Interests(n) (net of taxes of $7 and $5, respectively)
(34) (0.04) 20
 0.02
Adjusted (non-GAAP) Operating Earnings$686
 $0.71
 $524
 $0.56

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 Six Months Ended June 30,
 2018 2017
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$1,125
 $1.16
 $1,086
 $1.17
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $46 and $91, respectively)
129
 0.13
 142
 0.15
Unrealized Losses (Gains) Related to NDT Fund Investments(b) (net of taxes of $122 and $130, respectively)
147
 0.15
 (144) (0.15)
Amortization of Commodity Contract Intangibles(c) (net of taxes of $0 and $9, respectively)
—
 —
 15
 0.02
Merger and Integration Costs(d) (net of taxes of $2 and $25, respectively)
4
 —
 40
 0.04
Merger Commitments(e) (net of taxes of $0 and $137, respectively)
—
 —
 (137) (0.15)
Long-Lived Asset Impairments(f) (net of taxes of $11 and $172, respectively)
30
 0.03
 268
 0.29
Plant Retirements and Divestitures(g) (net of taxes of $78 and $42, respectively)
220
 0.23
 66
 0.07
Cost Management Program(h) (net of taxes of $6 and $7, respectively)
16
 0.02
 10
 0.01
Bargain Purchase Gain(i) (net of taxes of $0)
—
 —
 (226) (0.24)
Change in Environmental Liabilities (j) (net of taxes of $2 and $0, respectively)
5
 0.01
 —
 —
Like-Kind Exchange Tax Position(k) (net of taxes of $0 and $66, respectively)
—
 —
 (26) (0.03)
Reassessment of Deferred Income Taxes(l) (entire amount represents tax expense)
(8) (0.01) (20) (0.02)
Tax Settlements(m) (net of taxes of $0 and $1, respectively)
—
 —
 (5) (0.01)
Noncontrolling Interests(n) (net of taxes of $13 and $12, respectively)
(57) (0.06) 55
 0.06
Adjusted (non-GAAP) Operating Earnings$1,611
 $1.66
 $1,124
 $1.21
 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
___________________
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 2018 and 2017 ranged from 26.0 percent to 29.0 percent and 39.0 percent to 41.0 percent, respectively.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 48.945.4 percent and 31.440.3 percent for the three months ended June 30,March 31, 2019 and 2018, and 2017, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 45.3 percent and 47.5 percent for the six months ended June 30, 2018 and 2017, respectively.
(a)Reflects the impact of net gains and losses on Generation’s economic hedging activities. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information related to Generation’s hedging activities.
(b)
Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.
(c)(b)Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.

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(d)Primarily reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2017, reflects costs related to the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs, and in 2018, reflects costs related to the PHI acquisition. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information related to merger and acquisition costs.
(e)Primarily reflects a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.
(f)Primarily reflects charges to earnings related to the impairment of the EGTP assets held for sale in 2017, and in 2018 the impairment of certain wind projects at Generation.
(g)Primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the TMI nuclear facility in 2017. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility as well asand accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the TMI nuclear facility, and a loss associated with Generation's sale of Residential Solar Holding, LLC, 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 to early retire the TMI nuclear facility and a benefit associated with a remeasurement of the TMI ARO.
(h)(c)Represents severance andPrimarily represents reorganization costs related to a cost management program.programs.
(i)Represents the excess fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.
(j)Represents charges to adjust the environmental reserve associated with Cotter.
(k)Represents adjustments to income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.
(l)Reflects the change in the District of Columbia statutory tax rate in 2017, and in 2018, an adjustment to the remeasurement of deferred income taxes as a result of the TCJA.
(m)Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI’s unregulated business interests.
(n)(d)Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.
Significant 20182019 Transactions and Developments
Regulatory Implications of the Tax CutsUtility Rates and Jobs Act (TCJA)Base Rate Proceedings
The Utility Registrants have made filingsfile base rate cases with their respective State regulatorsregulatory commissions seeking increases or decreases to begin passing backtheir electric transmission and distribution, and gas distribution rates to customersrecover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the ongoing annual tax savings resulting fromUtility Registrants’ current and future financial statements.

The following tables show the TCJA. The amounts being proposed to be passed back to customers reflect the annual benefit of lower income tax ratesUtility Registrants’ completed and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. The Utility Registrants have identified over $675 millionpending distribution base rate case proceedings in ongoing annual savings to be returned to customers related to TCJA from their distribution utility operations.2019. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.information on other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateRequested Revenue Requirement IncreaseApproved Revenue Requirement Increase (Decrease)Approved ROEApproval DateRate Effective Date
BGE - Maryland (Natural Gas)June 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, 2019
Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateRequested Revenue Requirement 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 2019
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. On February 8, 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 active parties filed a status update with the presiding Administrative Law Judge requesting an additional 45 days to file a settlement. 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 RetirementsUtility Rates and Base Rate Proceedings
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle by October 2018. Because of the decisionThe Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to early retire Oyster Creek in 2018, Exelontheir electric transmission and Generation recognized certain one-time charges in the first quarter of 2018 relateddistribution, and gas distribution rates to a materials and supplies inventory reserve adjustment, employee-relatedrecover their costs and construction work-in-progress impairments, among other items.earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
On July 31, 2018, Generation entered into an agreement with Holtec International
The following tables show the Utility Registrants’ completed and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the sale and decommissioning of Oyster Creek.pending distribution base rate case proceedings in 2019. See Note 206 — Subsequent EventsRegulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.information on other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateRequested Revenue Requirement IncreaseApproved Revenue Requirement Increase (Decrease)Approved ROEApproval DateRate Effective Date
BGE - Maryland (Natural Gas)June 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, 2019
Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateRequested Revenue Requirement 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 2019
PECO Transmission Formula Rate
On May 30,1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. On February 8, 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 active parties filed a status update with the presiding Administrative Law Judge requesting an additional 45 days to file a settlement. 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 announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The plant is currently committedhad approximately $750 million and $500 million of net long-lived assets and nonrecourse debt outstanding, respectively, related to operate through May 2019.
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 early nuclear plant retirement decisions at Oyster Creekongoing event of default and TMI, Exelonthe 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 will also recognize annual incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciationassessed and determined that Antelope Valley’s long-lived assets were not impaired as of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with theMarch 31, 2019. Significant changes in decommissioning timing and cost assumptions were also

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recorded. The following table summarizes the actual incremental non-cash expense item incurredPPA being rejected as part of the bankruptcy proceedings could potentially result in 2018 andfuture impairments of Antelope Valley's net long-lived assets, which could be material. Generation is monitoring the estimatedbankruptcy proceedings for any changes in circumstances that would indicate the carrying amount of incremental non-cash expense items expected tothe net long-lived assets of Antelope Valley may not be incurred in 2018 and 2019 due to the early retirement decisions.recoverable.
 Actual 
Projected(a)
Income statement expense (pre-tax)Six Months Ended June 30, 2018 2018 2019
Depreciation and amortization(b)
     
         Accelerated depreciation(c)
$289
 $550
 $330
         Accelerated nuclear fuel amortization34
 55
 5
Operating and maintenance(d)
28
 30
 5
Total$351
 $635
 $340
_________
(a)Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.
(b)Reflects incremental accelerated depreciation and amortization for TMI and Oyster Creek for the six months ended June 30, 2018. The Oyster Creek year-to-date amounts are from February 2, 2018 through June 30, 2018.
(c)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(d)Primarily includes materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments.
In 2017, PSEG also made public financial challenges facing its New Jersey nuclear plants including Salem, of which Generation owns a 42.59% ownership interest. Although Salem is committed to operate through May 2021, the plant faces continued economic challenges and PSEG, as the operator of the plant, is exploring all options.
On May 23, 2018, the Governor of New Jersey signed new legislation, which became effective immediately, that will establish a ZEC program providing compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the new legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. The NJBPU has 180 days from the effective date to establish procedures for implementation of the ZEC program and 330 days from the effective date to determine which nuclear power plants are selected to receive ZECs under the program. Assuming the successful implementation of the New Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk of earlier retirement for Salem. See Note 67 — Regulatory MattersImpairment of Long-Lived Assets and Note 8 - Early Plant Retirements11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the new legislation and the New Jersey ZEC program.PG&E bankruptcy.
On March 29, 2018, based on ISO-NE capacity auction results for the 2021 - 2022 planning year in which Mystic unit 9 did not clear, Generation announced it had formally notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets on June 1, 2022 absent any interim and long-term solutions for reliability and regional fuel security. The ISO-NE announced that it would take a three-step approach to fuel security. First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic units 8 and 9 for fuel security for the 2022 - 2024 planning years.  Second, ISO-NE planned to file tariff revisions to allow it to retain other resources for fuel security in the capacity market if necessary in the future. Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic units 8 and 9, cannot recover future operating costs including the cost of procuring fuel. As a result of these developments, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group during the first quarter of 2018 and no impairment charge was required.

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On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic units 8 and 9 for the period between June 1, 2022 - May 31, 2024.
On July 2, 2018, FERC issued an order denying ISO-NE's May 1, 2018, waiver request on procedural grounds but accepting ISO-NE's conclusions that retirement of Mystic units 8 and 9 could cause a violation of mandatory reliability standards as soon as 2022. Accordingly, FERC ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address demonstrated fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. FERC also extended the deadline by which Generation must make a retirement decision for Mystic units 8 and 9 to January 4, 2019.
On July 13, 2018, FERC issued an order accepting the cost-of-service agreement for filing, making findings on certain issues and establishing hearing procedures on an expedited schedule. Further developments such as the failure of ISO-NE to adopt interim and long-term solutions for reliability and fuel security could potentially result in future impairments of the New England asset group, which could be material. See Note 7 — Impairment of Long-Lived Assets and Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Illinois ZEC Procurement
Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton unit 1, Quad Cities unit 1 and Quad Cities unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue. Winning bidders are entitled to compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. During the three months ended June 30, 2018, Generation recognized revenue of $52 million. During the six months ended June 30, 2018, Generation recognized revenue of $254 million, of which $150 million related to ZECs generated from June 1, 2017 through December 31, 2017.
Westinghouse Electric Company LLC Bankruptcy
On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. On January 4, 2018, Westinghouse announced its agreement to be purchased by an affiliate of Brookfield Business Partners, LLC (Brookfield) for approximately $4.6 billion. On March 28, 2018, the Bankruptcy Court entered an Order confirming the Debtor's Second Amended Joint Plan of Reorganization which provides for the transaction with Brookfield. Closing of the transaction is expected to occur in the third quarter of 2018. Exelon has contracts with Westinghouse primarily related to Generation's purchase of nuclear fuel, as well as a variety of services and equipment purchases associated with the operation and maintenance of nuclear generating stations. In conjunction with the confirmation hearing, Exelon had filed a reservation of rights regarding reorganizing Westinghouse's assumption of all Exelon contracts. Exelon has reached an agreement with Brookfield that all Exelon contracts will be assumed by Brookfield on the closing date. Closing of the transaction is subject to numerous conditions, including regulatory approvals.
Utility Rates and Base Rate Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position.

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statements.

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2018.2019. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
Registrant Jurisdiction 
Approved Revenue Requirement Increase (Decrease)
(in millions)
 Approved Return on Equity Completion Date Rate Effective Date
Pepco Maryland (Electric) $(15) 9.5% May 31, 2018 June 1, 2018
DPL Maryland (Electric) $13
 9.5% February 9, 2018 February 9, 2018
Registrant/JurisdictionFiling DateRequested Revenue Requirement IncreaseApproved Revenue Requirement Increase (Decrease)Approved ROEApproval DateRate Effective Date
BGE - Maryland (Natural Gas)June 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, 2019
Pending Distribution Base Rate Case Proceedings
Registrant Jurisdiction 
Requested or Settlement Revenue Requirement Increase (Decrease)
(in millions)
 Requested or Settlement Return on Equity Filing or Settlement Date Expected Completion Timing
ComEd Illinois (Electric) $(23) 8.69% April 16, 2018 Fourth quarter 2018
PECO Pennsylvania (Electric) $82
 10.95% March 29, 2018 Fourth quarter 2018
BGE Maryland (Natural Gas) $63
 10.50% June 8, 2018 First quarter 2019
Pepco District of Columbia (Electric) $(24) 9.525% December 19, 2017 (Updated on February 9, 2018 and April 17, 2018) Third quarter 2018
DPL Delaware (Electric) $(7) 9.70% August 17, 2017 (Updated on October 18, 2017, February 9, 2018 and June 27, 2018) Third quarter 2018
DPL Delaware (Natural Gas) $4
 10.10% August 17, 2017 (Updated on November 7, 2017 and February 9, 2018) Fourth quarter 2018
Registrant/JurisdictionFiling DateRequested Revenue Requirement 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 2019
See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these base rate case proceedings.

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Transmission Formula Rate
The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2018 annual electric transmission formula rate updates.
 2018
Annual Transmission Updates(a)(b)
ComEd BGE Pepco DPL ACE
Initial revenue requirement (decrease) increase$(44) $10
 $6
 $14
 $4
Annual reconciliation increase (decrease)18
 4
 2
 13
 (4)
Dedicated facilities increase(c)
—
 12
 —
 —
 —
Total revenue requirement (decrease) increase$(26) $26
 $8
 $27
 $—
          
Allowed return on rate base(d)
8.32% 7.61% 7.82% 7.29% 8.02%
Allowed ROE(e)
11.50% 10.50% 10.50% 10.50% 10.50%
_________
(a)All rates are effective June 2018, subject to review by the FERC and other parties, which is due by fourth quarter 2018.
(b)The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA.  See further discussion above. 
(c)BGE's transmission revenues include a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to a specifically designated load by BGE.
(d)Represents the weighted average debt and equity return on transmission rate bases.
(e)As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization.
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. On February 8, 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 active parties filed a status update with the presiding Administrative Law Judge requesting an additional 45 days to file a settlement. PECO cannot predict the final outcome of this proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a revenue decrease of $6 million. The revenue decrease of $6 million included an approximately $20 million reduction as a result of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.

TablePacific Gas & Electric Bankruptcy
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of Contents
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.
Winter Storm-Related CostsSee 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.
DuringEarly Plant Retirements
Oyster Creek. Generation permanently ceased generation operations at Oyster Creek in September 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. Generation currently anticipates satisfaction of the closing conditions for the transaction to occur in the second half of 2019. 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 generation operations at TMI on or about September 30, 2019. The plant is currently committed to operate through May 2019. As a result of the previous decision to early retire TMI, Exelon and Generation recorded a $4 million incremental pre-tax net benefit for the three months ended March 31, 2019 primarily due to a benefit associated with the remeasurement of the TMI ARO, partially offset by accelerated depreciation 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.
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 making authority to retire Salem. In 2018, there were powerful nor'easter stormsNew Jersey enacted legislation that broughtestablished a mix of heavy snow, ice and high sustained winds and gustsZEC program that provides compensation for nuclear plants that demonstrate to the regionNJBPU that interrupted electric service deliverythey meet certain requirements, including that they make a significant contribution to customersair quality in PECO's, BGE's, Pepco's, DPL'sthe state and ACE's service territories. Restoration efforts included significantthat their revenues are insufficient to cover their costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crewsrisks. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and supplies,Salem 2. Assuming 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 incremental operating and maintenance expense and incremental capital expendituresthe largest volume of nuclear capacity ever not selected in the first quarterauction, including all of 2018Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for PECO, BGE, PHI, Pepco, DPLbroader market reforms at the regional and ACE. In addition, PHI, Pepco, DPLfederal level.
See Note 6 — Regulatory Matters, Note 8 — Early Plant Retirements and ACE recorded regulatory assetsNote 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for amounts that are probable of recovery through customer rates. The impacts recorded by the Registrants for the six months ended June 30, 2018 are presented below:additional information.
   (in millions)
 Customer Outages Incremental Operating & Maintenance Incremental Capital Expenditures
Exelon1,727,000
 $92
(b) 
$93
PECO750,000
 54
 36
BGE425,000
 31
 15
PHI(a)
552,000
 7
(b) 
42
Pepco182,000
 3
(b) 
6
DPL138,000
 4
(b) 
5
ACE232,000
 —
(b) 
31
________
(a)PHI reflects the consolidated customer outages, incremental operating & maintenance and incremental capital expenditures of Pepco, DPL and ACE.
(b)Excludes amounts that were deferred and recognized as regulatory assets at Exelon, PHI, Pepco, DPL and ACE of $25 million, $25 million, $5 million, $1 million and $19 million, respectively.

Exelon’s Strategy and Outlook for 20182019 and Beyond
Exelon’s value proposition and competitive advantage come from its scope and its core strengths of operational excellence and financial discipline. Exelon leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition:
The Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and in long-term, contracted assets and to reduce debt.
Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid and smart meter

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technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon's Board of Directors has approved a dividend policy providing a raise of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS of the Exelon 20172018 Form 10-K for additional information regarding market and financial factors.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy.  In August 2015, Exelon announced a cost management program focused on cost savings of approximately $400 million at BSC and Generation, of which approximately 60% of run-rate savings was achieved by the end of 2017 with the remainder to be fully realized in 2018.  At leastApproximately 75% of the savings are expected to bewere related to Generation, with the remaining amount related to the Utility Registrants. Additionally, inIn November 2017, Exelon announced a new commitment for an additional $250 million of cost savings, primarily at Generation, to be achieved by 2020. In November 2018, Exelon announced the elimination of an approximately additional $200 million of annual ongoing costs, through initiatives primarily at Generation and BSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity.

Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The PHI merger provides an opportunity to accelerate Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support.  Additionally, the Utility Registrants anticipate investing approximately $26$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 $11$13 billion by the end of 2022.2023. 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.

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See Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements Exelon 20172018 Form 10-K for additional information on the Smart Meter and Smart Grid Initiatives and infrastructure development and enhancement programs.
Competitive Energy Businesses. Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.
Liquidity Considerations
Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
Exelon Corporate, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6 billion, $5.3 billion, $1 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively.facilities. Generation also has bilateral credit facilities with aggregate maximum availabilityfacilities. Refer to Note 13 — Debt and Credit Agreements of $0.5 billion.the Exelon 2018 Form 10-K for additional information on credit facilities.
For additional information regarding the Registrants' liquidity for the sixthree months ended June 30, 2018,March 31, 2019, see Liquidity and Capital Resources discussion below.
Project Financing
Generation utilizes individual project financings as a meansProject financing is used to finance the constructionhelp mitigate risk of variousspecific generating asset projects.assets. Project financing is based upon a nonrecourse financial structure, in which project debt and equity used to finance the project areis paid back from the cash generated by the newly constructedspecific asset once operational.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 debt and Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.

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the Pacific Gas and Electric Company bankruptcy.

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

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cash flows and results of operations. The same risk would also exist for the Salem facility if the NJ ZEC program is successfully implemented and Salem is selected as an eligible facility.
Separately, PJM submitted two proposed alternative capacity market reforms in April 2018 for FERC’s consideration. PJM argued that either alternative will resolve any conflict between state policy support for certain resources and the need to ensure reasonable prices for non-supported resources. The first alternative was to implement a twice-run capacity clearing mechanism (known as the repricing proposal) and, if not acceptable to FERC, a second alternative that would expand the existing MOPR to both new and existing generating resources, subject to certain exemptions (known as MOPREx).
In June 2018, FERC issued an order rejecting both of PJM’s proposed alternatives, finding both to be unjust and unreasonable. In the same order, FERC also addressed one of the MOPR complaints involving PJM and concluded based on that complaint and PJM’sa 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. FERC suggested that modifying two elements of PJM’s existing tariff could produce a just and reasonable replacement and asked for initial comments on its proposal by August 28, 2018, later extended to October 2, 2018. First, FERC found that an expansion of the current MOPR mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or REC compensation, could protect the capacity markets from unwanted price suppression. Second, FERC preliminarily found that a modified version of PJM’s existing Fixed Resource Requirement (FRR) option could enable state subsidized resources and a corresponding amount of load to be removed from the capacity market, thereby alleviating their price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through mechanisms other than through PJM’s existing market mechanism. FERC indicated that it aims to render a decision prior to January 4, 2019 and established March 21, 2016 as the refund effective date.date and also allowed PJM to delay its next capacity auction from May 2019 to August 2019 to allow parties time to develop and file proposals in the FERC proceeding, FERC time to determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates, environmental organizations and other nuclear generators, submitted shared principles supporting a workable new FRR mechanism (as suggested by FERC) and detailing how such a mechanism should be implemented. Exelon also submitted individual comments covering matters not addressed in the shared principles. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. 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. 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)as amended, (the Act) from imports of uranium products, alleging that these imports threaten national security (the Petition). The Trade Expansion Act of 1962 (the Act) was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.
On July 18, 2018, the Secretary announced that the DOC hashad initiated an investigation in response to the petition. The Secretary has 270 days to prepare and submitsubmitted a report to President Trump who thenon April 14, 2019. The President now has 90 days to decide whether and how to act on the Secretary's recommendations. Exelon and Generation cannot currently predict the outcome of this investigation. The relief sought by the petitioners would require U.S. nuclear reactors to purchase at least 25% of their uranium needs from domestic mines overfor the next 10 years or more, although the President could choose this remedy or any other remedy, whether recommended by the DOC will make an independent determination regarding an appropriate remedy should it find that imports impair national security.or not, or could choose to take no action. 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’s and Generation’s results of operations, cash flows and financial positions.

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Potential DOE Order Pursuant to Defense Production Act and Federal Power Act
The DOE is considering an Order directing ISOs, for 24 months, to purchase electric energy or generation capacity from a designated list of coal and nuclear generation facilities. Based on a draft memorandum, the Order would be pursuant to DOE's authorities under the Defense Production Act and Federal Power Act, and would forestall any further actions towards retiring, decommissioning, or deactivating coal and nuclear facilities during the term of the Order. The Order would emphasize the importance of grid resiliency, in addition to grid reliability, noting that fuel security and diversity are critical components of resiliency. The DOE recognizes that the underlying economic and regulatory issues are complex and will take time resolve. The Order's 24-month duration would enable DOE to conduct additional analyses to gain a detailed understanding of location-specific vulnerabilities in U.S. energy delivery systems, while preserving certain generation facilities. Exelon has been and will continue to be an active participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.statements.
Energy Demand
Modest economic growth partially offset by energy efficiency initiatives is resulting in relatively flat load growth in electricity for the Utility Registrants. ComEd, PECO, BGE, Pepco, DPL and ACE are projecting load volumes to increase (decrease) by 0.7%(0.2)%, 0.6%(0.3)%, 0.7%1.3%, 0.6%, 1.0%(0.7)% and 2.1%(1.9)% respectively, in 20182019 compared to 2017.2018. 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 20182019 dividends of $0.345$0.3625 per share on Exelon's common stock. The first quarter 20182019 dividend was paid on March 9, 2018. The8, 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 increased from the fourth quarter 2017 amount to reflect the Board's decision to raise Exelon's dividendpolicy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
Exelon's board of directors declared second quarter 2018 dividends of $0.345 per share on Exelon's common stock and was paid on June 8, 2018.
Exelon's board of directors declared third quarter 2018 dividends of $0.345 per share on Exelon's common stock and is payable on September 10, 2018.
All future quarterly dividends require approval by Exelon's Board of Directors.
Hedging Strategy
Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk

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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 20182019 and 2019.2020. 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 June 30, 2018,March 31, 2019, the percentage of expected generation hedged is 97%-100%90%-93%, 71%-74%64%-67% and 41%-44%38%-41% for 2018, 2019, 2020, and 20202021 respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.
Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal, oil and natural gas are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 59%62% of Generation’s uranium concentrate requirements from 20182019 through 20222023 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.statements.
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.

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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, the Coal Combustion Residuals rule, 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, EPA issued a proposed rule to repeal the CPP in its entirety, based on a proposed change in the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. TheSubsequently, on August 31, 2018, EPA has also issued an advance noticeproposed its Affordable Clean Energy Rule, which would replace the CPP with revised emission guidelines based on heat rate improvement measures that could be achieved within the fence line of proposed rulemaking to solicit information on systems of emission reduction that are in accord with the Agency’s proposed revised legal interpretation; namely, only by regulating emission reductions that can be implemented at and to individual sources.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

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national GHG emissions. In June 2018, Exelon joined the Climate Leadership Council, which advocates for a revenue neutral carbon tax and dividend program. In the absence of Federal legislation, the EPA has been reviewingis 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 20172018 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 unitUnit 7, Nine Mile Point unitUnit 1, Peach Bottom, Quad Cities, and Salem. See ITEM 1. BUSINESS, "Water Quality" of the Exelon 20172018 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 1716 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to environmental matters, including the impact of environmental regulation.
Other Legislative and Regulatory Developments
Delaware Distribution System Investment ChargeIllinois Clean Energy Progress Act
On JuneMarch 14, 2018,2019, the GovernorClean 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 Delaware signedPJM’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 Distribution System Investment Charge (DSIC) legislation, whichclean energy resources, (2) it establishes a system improvement charge that provides a mechanism to recover infrastructure investments, allowing for gradual rate increases and limiting frequencygoal of distribution base rate cases.  DPL expects to make its first filing in Delawareachieving 100% carbon-free power in the fourth quarter of 2018, with the new charge effectiveComEd service territory by 2032, and (3) it implements reforms to enhance consumer protections in the first quarter of 2019.  While thisstate’s competitive retail electricity and natural gas markets, including Generation’s retail customers. Energy legislation is expected to support needed infrastructure investmenthas also been proposed by other stakeholders, including renewable resource developers, environmental advocates, and allow for more timely recovery of those investments, Exelon, PHI and DPL cannot predict the potential financial impact on Exelon, PHI or DPL.
Pennsylvania Alternative Ratemaking
On June 28, 2018, the Governor of Pennsylvania signed new legislation, which authorized the PAPUC to review and approve utility-proposed alternative rate mechanisms, including options such as decoupling mechanisms, formula rates, multi-year rate plans, and performance based rates.coal-fueled generators. Exelon and PECOGeneration are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or PECO.Generation.

Keep Powering Pennsylvania Act
TableOn March 11, 2019, the Keep Powering Pennsylvania Act was introduced in the Pennsylvania General Assembly to amend the Alternative Energy Portfolio Standards Act of Contents
2004. The proposed legislation recognizes the value that all zero-emission electric generation resources provide to Pennsylvania by adding nuclear plants and certain other renewable generation resources (Tier III resources) to the zero-emission electric generation resources that currently receive alternative energy credits in Pennsylvania. Further, the proposed legislation would allow for these Tier III resources to continue to receive capacity payments at the same level as the PJM capacity auction clearing price. In order to initially qualify as a Tier III resource, a resource must make a commitment to operate for at least six years. The price of the alternative energy credits for Tier III resources is tied to the value of existing Tier I resources, with a price cap. Regulated utilities, including PECO, would be required to purchase alternative energy credits for all retail customers and allowed to recover those costs from customers. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.

Nuclear Powers Act of 2019
On April 12, 2019, the Nuclear Powers America Act of 2019 was introduced to the United States Congress, which expands the current investment tax credit to existing nuclear power plants. The proposed legislation would provide a credit equal to 30% of continued capital investment in certain nuclear energy-related expenditures, including capital expenses and nuclear fuel, starting from tax years 2019 through 2023. Thereafter, the credit rate would be reduced to 26% in 2024, 22% in 2025, and 10% in 2026 and beyond. To qualify for the credit, the plant must be currently operational and must have applied for an operating license renewal before 2026.  Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Employees
In January 2017, anDuring 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, at BGE which resulted inand the new union representationnamed "LEOSU" prevailed. Negotiations will begin for approximately 1,394 employees. BGE and IBEW Local 410 are negotiating an initial agreement with LEOSU which could result in some modifications to wages, hours and other terms and conditions of employment. Negotiations have been productive and continue. No agreement has been finalized to date and managementManagement 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 that began in 2017continue between BGE and IBEW Local 410 for a first collective bargaining agreement withcontract and it is not certain when negotiations will conclude but we anticipate a small unit of employees represented by Local 501 of Operating Engineers at Exelon’s Hyperion Solutions facility are ongoing. During 2017, Generation finalizedfavorable outcome. In April 2019, the CBAs with the Security Officer unionsIBEW Local 15 covering employees at LaSalle, LimerickBSC, ComEd and Quad Cities, which all will expire in 2020 and Dresden expiring in 2021. Additionally, during 2017, Generation, acquired and combined two CBAs at Fitzpatrick into one CBA covering both craft and security employees, which will expire in 2023. Generation also successfully finalized the CBA with the IBEW union at TMI, which will expire in 2022. Prior to commencing negotiations with the Security Officer union at Braidwood, a rival union petitioned the NLRB to represent the Security Officers in lieu of the incumbent Union. An election was held, and the incumbent Union prevailed. The existing CBA was extended prior to the NLRB hearingthrough 2024. The CBA between Pepco and currently expires in August 2018. Negotiations began in June and have been productive and continue. In June 2018, an NLRB election was held involving 18 system operators at the ACE control room seeking potential representation by IBEW Local 210. The election was certified1900 is scheduled to expire on July 9, 2018, recognizing IBEW Local 210 as the representative of ACE system operators. On July 23, 2018, ACE filedMay 26, 2019. Negotiations have begun this month and we anticipate a Request for Review by the NLRB of the Regional Director's June 15, 2018 decision finding that the system operators are not supervisors under the National Labor Relations Act. The request is pending.positive outcome.
Critical Accounting Policies and Estimates
Revenue Recognition (All Registrants)
Sources of Revenue and Determination of Accounting Treatment
The Registrants earn revenues from various business activities including: the sale of power and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail); the sale and delivery of power and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services.
The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from Contracts with Customers, Derivative and Alternative Revenue Program (ARP) guidance to recognize revenue as discussed in more detail below.
Revenue from Contracts with Customers
Under the Revenue from Contracts with Customers guidance, the Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power, natural gas, and other energy-related commodities are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as normal purchases and normal sales (NPNS), sales to utility customers under regulated service tariffs, and spot-market energy commodity sales, including settlements with independent system operators.
The determination of Generation’s and the Utility Registrants' retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally on a monthly basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled

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revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the utilities’ customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternate supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged.
See Note 5 — Accounts Receivable of the Exelon 2017 Form 10-K for additional information on unbilled revenue.
See Note 1 — Significant Accounting Policies and Note 5 — Revenue from Contracts with Customers of the Combined Notes to Consolidated Financial Statements for additional information on the impacts of the new revenue accounting standard effective for annual reporting periods beginning on or after December 15, 2017.
Derivative Revenues
The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses include: inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses.
Alternative Revenue Program Revenues
Certain of the Utility Registrants’ ratemaking mechanisms qualify as Alternative Revenue Programs (ARPs) if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, which include the Utility Registrants’ formula rate and revenue decoupling mechanisms, the Utility Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated

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reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts.
See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — CRITICAL ACCOUNTING POLICIES AND ESTIMATES in Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's combined 20172018 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 June 30, 2018,March 31, 2019, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2017.2018.
Results of Operations by Registrant
Net Income (Loss) AttributableThe Registrants' Results of Operations includes discussion of RNF, which is a financial measure not defined under GAAP and may not be comparable to Common Shareholdersother 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 Registranttheir 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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 Three Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 Six Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Exelon$539
 $95
 $444
 $1,125
 $1,086
 $39
Generation178
 (235) 413
 314
 184
 130
ComEd164
 118
 46
 329
 259
 70
PECO96
 88
 8
 210
 215
 (5)
BGE51
 45
 6
 179
 169
 10
PHI84
 66
 18
 149
 205
 (56)
Pepco54
 43
 11
 85
 101
 (16)
DPL26
 19
 7
 57
 76
 (19)
ACE8
 8
 —
 15
 36
 (21)

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Results of Operations — Generation
 Three Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 Six Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$4,579
 $4,216
 $363
 $10,090
 $9,093
 $997
Purchased power and fuel expense2,280
 2,157
 (123) 5,573
 4,955
 (618)
Revenues net of purchased power and fuel expense(a)
2,299
 2,059
 240
 4,517
 4,138
 379
Other operating expenses           
Operating and maintenance1,418
 2,012
 594
 2,756
 3,503
 747
Depreciation and amortization466
 334
 (132) 914
 637
 (277)
Taxes other than income134
 140
 6
 272
 282
 10
Total other operating expenses2,018
 2,486
 468
 3,942
 4,422
 480
Gain on sales of assets and businesses1
 —
 1
 54
 4
 50
Bargain purchase gain—
 —
 —
 —
 226
 (226)
Operating income (loss)282

(427) 709
 629

(54) 683
Other income and (deductions)           
Interest expense, net(102) (129) 27
 (202) (228) 26
Other, net29
 181
 (152) (15) 440
 (455)
Total other income and (deductions)(73) 52
 (125) (217) 212
 (429)
Income (loss) before income taxes209
 (375) 584
 412
 158
 254
Income taxes23
 (148) (171) 32
 (25) (57)
Equity in losses of unconsolidated affiliates(5) (9) 4
 (12) (19) 7
Net income (loss)181

(236)
417

368

164

204
Net income (loss) attributable to noncontrolling interests3
 (1) (4) 54
 (20) (74)
Net income (loss) attributable to membership interest$178
 $(235) $413
 $314
 $184
 $130
_________
(a)Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
Net Income Attributable to Membership Interest
 Three Months Ended
March 31,		 
Favorable
(Unfavorable)
Variance
 2019 2018 
Operating revenues$5,296
 $5,512
 $(216)
Purchased power and fuel expense3,205
 3,293
 88
Revenues net of purchased power and fuel expense(a)
2,091
 2,219
 (128)
Other operating expenses     
Operating and maintenance1,218
 1,339
 121
Depreciation and amortization405
 448
 43
Taxes other than income135
 138
 3
Total other operating expenses1,758
 1,925
 167
Gain on sales of assets and businesses—
 53
 (53)
Operating income333

347
 (14)
Other income and (deductions)     
Interest expense, net(111) (101) (10)
Other, net430
 (44) 474
Total other income and (deductions)319
 (145) 464
Income before income taxes652
 202
 450
Income taxes224
 9
 (215)
Equity in losses of unconsolidated affiliates(6) (7) 1
Net income422

186

236
Net income attributable to noncontrolling interests59
 50
 (9)
Net income attributable to membership interest$363
 $136
 $227
Three Months Ended June 30, 2018March 31, 2019 Compared to Three Months Ended June 30, 2017.March 31, 2018. Generation’s Net income attributable to membership interest for the three months ended June 30, 2018 increased compared to the same period in 2017,by $227 million primarily due to higher Revenue net of purchased power and fuel expense, lower Operating and maintenance expenses, partially offset by higher Depreciation and amortization expenses, lower Other income and higher income taxes. The increaseto:

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Net unrealized gains on NDT funds in Revenue net of purchased power and fuel expense primarily relates to mark-to-market gains in 20182019 compared to losses in 2017, increased capacity prices, decreased nuclear outage days,2018;
Decreased mark-to-market losses;
A benefit associated with the impactremeasurement of the Illinois ZESTMI ARO; and the impacts of Generation's natural gas portfolio,
Increased capacity prices.
The increases were partially offset by lowerby:
Lower realized energy prices and lower energy efficiency revenues.
The decreaseabsence of the revenues recognized in Operating and maintenance expense is primarily due to the impairment of EGTP assets held for sale in 2017, decreased nuclear outage days infirst quarter 2018 decreased spending related to energy efficiency projects, decreased costs related to the sale of Generation's electrical contracting business and one-time charges related to Generation's decision to early retire the TMI nuclear facility in 2017, partially offset by long-lived asset impairments of certain merchant wind assets in West Texas in 2018. The increase in Depreciation and amortization is primarily due to accelerated depreciation and amortization expenses associated with Generation's decision to early retire the Oyster Creek and TMI nuclear facilities. The decrease in Other income is primarily due to the change in realized and unrealized gains and losses on NDT funds. The decrease in income taxes is primarily due to tax savings related to the TCJA.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017.Generation’s Net income attributable to membership interest for the six months ended June 30, 2018 increased compared to the same period in 2017, primarily due to higher Revenue net of purchased power and fuel expense, lower Operating and maintenance expenses and higher Gain on sales of assets and businesses, partially offset by higher Depreciation and amortization expenses, a Bargain purchase gain in 2017, lower Other income, and higher Net income attributable to noncontrolling interests. The increase in Revenue net of purchased power and fuel expense primarily relates to the impacts of the New York CES and Illinois ZES (including the impact of zero emission creditsZECs generated in Illinois from June 1, 2017 through December 31, 2017), increased capacity prices, the acquisition of the FitzPatrick nuclear facility, decreased nuclear outage days, decreased mark-to-market losses in 2018 compared to 2017, impacts of Generation's natural gas portfolio and the addition of two combined-cycle gas turbines in Texas, partially offset by the impact of the deconsolidation of EGTP in 2017, the conclusion of the Ginna Reliability Support Services Agreement, lower energy efficiency revenues and lower realized energy prices. The decrease in Operating and maintenance is primarily due to the impairment of EGTP assets held for sale in 2017, decreased nuclear outage days in 2018, one-time charges associated with Generation's decision to early retire the TMI nuclear facility in 2017, certain costs associated with mergers and acquisitions related to the PHI and FitzPatrick acquisitions, and the impact of a supplemental NEIL distribution, partially offset by long-lived asset impairments of certain merchant wind assets in West Texas in 2018 and one-time charges associated with Generation's decision to early retire the Oyster Creek facility in 2018. The increase in Gain on sales of assets and businesses is primarily due to Generation's sale of its electrical contracting business. The increase in Depreciation and amortization is primarily due to accelerated depreciation and amortization expenses associated with Generation's decision to early retire the Oyster Creek and TMI nuclear facilities. The Bargain purchase gain in 2017 is due to the acquisition of the FitzPatrick nuclear facility. The decrease in Other income is primarily due to the change in unrealized gains and losses on NDT funds. The increase in income taxes is primarily due to lower income taxes in 2017 due to Generation's 2017 Net loss.2017.
Revenues Net of Purchased Power and Fuel Expense
Expense.The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned with these same geographic regions. Descriptions of each of Generation’s sixGeneration'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 follows:a separate region by the CODM nor will it be presented

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.148

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Midwest represents operationsseparately in any external information presented to third parties. Information for the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.
New England represents region will be reviewed by the operations within ISO-NE covering the statesCODM as part of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.
New York represents operations within ISO-NY, which covers the state of New York in its entirety.
ERCOT represents operations within Electric Reliability Council of Texas, covering mostOther Power Regions. See Note 24 - Segment Information of the state of Texas.
Other Power Regions:
South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.
West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota.
Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.
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 Generation's overall operating revenues or results of operations. Further, the following activities are not allocated to a region and are reported in Other: amortization of certain intangible assets relating to commodity contracts recorded at fair value from mergers and acquisitions; accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.
Generation evaluates the operating performance of its electric business activities using the measure of Revenue net of purchased power and fuel expense, which is a non-GAAP measurement. Generation’s operatingRNF. 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 six months ended June 30,March 31, 2019 and 2018, and 2017, Generation’s Revenue net of purchased power and fuel expenseRNF by region were as follows:
Three Months Ended
June 30,		 Variance % Change Six Months Ended
June 30,		 Variance % ChangeThree Months Ended
March 31,		 Variance % Change
2018 2017 2018 2017 2019 2018 
Mid-Atlantic(a)
$735
 $783
 $(48) (6.1)% $1,586
 $1,557
 $29
 1.9 %$683
 $850
 $(167) (19.6)%
Midwest(b)
772
 728
 44
 6.0 % 1,631
 1,443
 188
 13.0 %771
 860
 (89) (10.3)%
New England96
 147
 (51) (34.7)% 216
 257
 (41) (16.0)%
New York(d)
266
 270
 (4) (1.5)% 549
 415
 134
 32.3 %
New York265
 283
 (18) (6.4)%
ERCOT82
 70
 12
 17.1 % 118
 138
 (20) (14.5)%74
 36
 38
 105.6 %
Other Power Regions90
 90
 —
 — % 208
 152
 56
 36.8 %156
 236
 (80) (33.9)%
Total electric revenue net of purchased power and fuel expense2,041
 2,088
 (47) (2.3)% 4,308
 3,962
 346
 8.7 %1,949
 2,265
 (316) (14.0)%
Proprietary Trading29
 7
 22
 314.3 % 35
 7
 28
 400.0 %4
 6
 (2) (33.3)%
Mark-to-market gains (losses)90
 (184) 274
 (148.9)% (175) (233) 58
 (24.9)%
Other(c)
139
 148
 (9) (6.1)% 349
 402
 (53) (13.2)%
Mark-to-market losses(28) (266) 238
 (89.5)%
Other166
 214
 (48) (22.4)%
Total revenue net of purchased power and fuel expense$2,299
 $2,059
 $240
 11.7 % $4,517
 $4,138
 $379
 9.2 %$2,091
 $2,219
 $(128) (5.8)%
_________
(a)ResultsIncludes results of transactions with PECO, and BGE, are included in the Mid-Atlantic region. Results of transactions with Pepco, DPL and ACE are included in the Mid-Atlantic region.ACE.
(b)ResultsIncludes results of transactions with ComEd are included in the Midwest region.ComEd.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes amortization of intangible assets related to commodity contracts recorded at fair value of a $20 million decrease to revenue net of purchased power and fuel expense for the three months ended June 30, 2017, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements of a $20 million decrease and $2 million decrease to revenue net of purchased power and fuel expense for the three months ended June 30, 2018 and 2017, respectively. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of a $22 million decrease to revenue net of purchased power and fuel expense for the six months ended June 30, 2017, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements of a $34 million decrease and $2 million decrease to revenue net of purchased power and fuel expense for the six months ended June 30, 2018 and 2017, respectively.
(d)Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

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Generation’s supply sources by region are summarized below:
Three Months Ended
June 30,		 Variance % Change Six Months Ended
June 30,		 Variance % ChangeThree Months Ended
March 31,		 Variance % Change
Supply source (GWhs)2018 2017 2018 2017 2019 2018 
Nuclear Generation                      
Mid-Atlantic(a)
16,498
 15,246
 1,252
 8.2 % 32,727
 31,790
 937
 2.9 %15,080
 16,229
 (1,149) (7.1)%
Midwest23,100
 22,592
 508
 2.2 % 46,698
 45,061
 1,637
 3.6 %23,733
 23,597
 136
 0.6 %
New York(c)(a)
6,125
 6,227
 (102) (1.6)% 13,239
 10,718
 2,521
 23.5 %6,902
 7,115
 (213) (3.0)%
Total Nuclear Generation45,723
 44,065
 1,658
 3.8 % 92,664

87,569
 5,095
 5.8 %45,715

46,941
 (1,226) (2.6)%
Fossil and Renewables            

 

    

 

Mid-Atlantic907
 899
 8
 0.9 % 1,807
 1,734
 73
 4.2 %951
 900
 51
 5.7 %
Midwest321
 417
 (96) (23.0)% 776
 835
 (59) (7.1)%392
 455
 (63) (13.8)%
New England816
 1,925
 (1,109) (57.6)% 2,851
 4,002
 (1,151) (28.8)%
New York1
 1
 —
 — % 2
 2
 —
 — %1
 1
 —
 — %
ERCOT2,303
 2,315
 (12) (0.5)% 5,252
 3,684
 1,568
 42.6 %3,078
 2,949
 129
 4.4 %
Other Power Regions2,221
 2,084
 137
 6.6 % 4,214
 3,507
 707
 20.2 %3,141
 4,028
 (887) (22.0)%
Total Fossil and Renewables6,569
 7,641
 (1,072) (14.0)% 14,902

13,764
 1,138
 8.3 %7,563

8,333
 (770) (9.2)%
Purchased Power            

 

    

 

Mid-Atlantic557
 2,901
 (2,344) (80.8)% 1,323
 6,299
 (4,976) (79.0)%2,566
 766
 1,800
 235.0 %
Midwest223
 413
 (190) (46.0)% 559
 801
 (242) (30.2)%288
 336
 (48) (14.3)%
New England5,953
 4,343
 1,610
 37.1 % 11,390
 9,407
 1,983
 21.1 %
New York—
 —
 —
 — % —
 28
 (28) (100.0)%
ERCOT2,320
 1,871
 449
 24.0 % 3,692
 4,525
 (833) (18.4)%1,042
 1,373
 (331) (24.1)%
Other Power Regions4,502
 3,507
 995
 28.4 % 8,635
 6,375
 2,260
 35.5 %12,569
 9,570
 2,999
 31.3 %
Total Purchased Power13,555
 13,035
 520
 4.0 % 25,599

27,435
 (1,836) (6.7)%16,465

12,045
 4,420
 36.7 %
Total Supply/Sales by Region            

 

    

 

Mid-Atlantic(b)
17,962
 19,046
 (1,084) (5.7)% 35,857
 39,823
 (3,966) (10.0)%18,597
 17,895
 702
 3.9 %
Midwest(b)
23,644
 23,422
 222
 0.9 % 48,033
 46,697
 1,336
 2.9 %24,413
 24,388
 25
 0.1 %
New England6,769
 6,268
 501
 8.0 % 14,241
 13,409
 832
 6.2 %
New York6,126
 6,228
 (102) (1.6)% 13,241
 10,748
 2,493
 23.2 %6,903
 7,116
 (213) (3.0)%
ERCOT4,623
 4,186
 437
 10.4 % 8,944
 8,209
 735
 9.0 %4,120
 4,322
 (202) (4.7)%
Other Power Regions6,723
 5,591
 1,132
 20.2 % 12,849
 9,882
 2,967
 30.0 %15,710
 13,598
 2,112
 15.5 %
Total Supply/Sales by Region65,847
 64,741
 1,106
 1.7 % 133,165

128,768
 4,397
 3.4 %69,743

67,319
 2,424
 3.6 %
_________
(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 and BGE in the Mid-Atlantic region, affiliate sales to ComEd in the Midwest region and affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region.
(c)Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

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Mid-Atlantic
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017. The $48 million decrease in Revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower realized energy prices, partially offset by decreased nuclear outage days and increased capacity prices.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017. The $29 million increase in Revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects decreased nuclear outage days and increased capacity prices, partially offset by lower realized energy prices.
Midwest
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017. The $44 million increase in Revenue net of purchased power and fuel expense in the Midwest was primarily due to the impact of the Illinois ZES, increased capacity prices, and decreased nuclear outage days, partially offset by lower realized energy prices.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017. The $188 million increase in Revenue net of purchased power and fuel expense in the Midwest was primarily due to the impact of the Illinois ZES (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017), decreased nuclear outage days, and increased capacity prices, partially offset by lower realized energy prices.
New England
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017. The $51 million decrease in Revenue net of purchased power and fuel expense in New England primarily reflects lower realized energy prices, partially offset by increased capacity prices.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017. The $41 million decrease in Revenue net of purchased power and fuel expense in New England primarily reflects lower realized energy prices, partially offset by increased capacity prices.
New York
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017. The $4 million decrease in Revenue net of purchased power and fuel expense in New York was primarily due to increased nuclear outage days which resulted in decreased ZEC revenues related to New York CES.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017. The $134 million increase in Revenue net of purchased power and fuel expense in New York was primarily due to the impact of the New York CES and the acquisition of FitzPatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement.
ERCOT
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017. The $12 million increase in Revenue net of purchased power and fuel expense in ERCOT was primarily due to higher realized energy prices.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017. The $20 million decrease in Revenue net of purchased power and fuel expense in ERCOT was primarily due to

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the deconsolidation of EGTP in 2017 and lower realized energy prices, partially offset by the addition of two combined-cycle gas turbines in Texas.
Other Power Regions
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017. There was an immaterial change in Revenue net of purchased power and fuel expense in Other Power Regions.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017. The $56 million increase in Revenue net of purchased power and fuel expense in Other Power Regions was primarily due to higher realized energy prices.
Proprietary Trading
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017. The $22 million increase in Revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017. The $28 million increase in Revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.
Mark-to-market
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017. Mark-to-market gains on economic hedging activities were $90 million forFor the three months ended June 30,March 31, 2019 and 2018, compared to losses of $184 million for the three months ended June 30, 2017. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on gains and losses associated with mark-to-market derivatives.changes in
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017.RNF Mark-to-market losses on economic hedging activitiesby region were $175 million for the six months ended June 30, 2018 compared to losses of $233 million for the six months ended June 30, 2017. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on gains and losses associated with mark-to-market derivatives.
Other
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017. The $9 million decrease in Revenue net of purchased power and fuel expense in Other was due to the decline in revenues related to the energy efficiency business and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements, partially offset by Generation's higher natural gas portfolio optimization and the absence of amortization of energy contracts recorded at fair value associated with prior acquisitions.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017. The $53 million decrease in Revenue net of purchased power and fuel expense in Other was due to the decline in revenues related to the energy efficiency business and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements, partially offset by Generation's higher natural gas portfolio optimization and the absence of amortization of energy contracts recorded at fair value associated with prior acquisitions.follows:

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 2019 vs. 2018
 Increase/ (Decrease)Description
Mid-Atlantic$(167)
• lower realized energy prices
• decreased revenue due to permanent cease of generation operations at Oyster Creek in Q3 2018, partially offset by
• increased capacity prices
Midwest$(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
New York$(18)• lower realized energy prices
ERCOT$38
• higher realized energy prices
Other Power Regions$(80)
• lower realized energy prices
• decreased capacity prices
Proprietary Trading$(2)• congestion activity
Mark-to-market(a)
$238
• losses on economic hedging activities of $28 million in 2019 compared to losses of $266 million in 2018
Other$(48)• the impacts of declining natural gas prices
Total$(128) 
_________
(a)See Note 10 — Derivative Financial Instruments for additional information on mark-to-market losses.
Nuclear Fleet Capacity Factor
Factor.The following table presents nuclear fleet operating data for the three and six months ended June 30, 2018 compared to the same period in 2017 for the Generation-operated plants.plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
March 31,
2018 2017 2018 20172019 2018
Nuclear fleet capacity factor(a)
93.2% 90.9% 94.8% 92.4%97.1% 96.5%
Refueling outage days(a)
94
 125
 162
 220
74
 68
Non-refueling outage days(a)
2
 12
 8
 20
—
 6
_________
(a)Reflects ownership percentage of stations operated by Exelon. Excludes Salem, which is operated by PSEG Nuclear, LLC. Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.
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Generation

Operating and Maintenance Expense
The changes in Operating and maintenance expense for the three and six months ended June 30, 2018 as compared to the same period in 2017, consisted of the following:
Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018		Three Months Ended
March 31, 2019
Increase (Decrease)(a)
 
Increase (Decrease)(a)
Increase (Decrease)
Labor, other benefits, contracting, materials(b)(a)
$(60) $(113)$(34)
Nuclear refueling outage costs, including the co-owned Salem plants(c)
(64) (96)6
Corporate allocations(1) 7
(10)
Insurance(d)(b)
(3) (36)30
Merger and integration costs(e)
(18) (55)(4)
Plant retirements and divestitures(f)(c)
(69) (42)(101)
Change in environmental liabilities(g)
7
 7
Cost management program5
 4
7
Long-lived asset impairments(h)
(379) (378)
Long-lived asset impairments5
Pension and non-pension postretirement benefits expense(7) (10)(16)
Allowance for uncollectible accounts(11) (10)(11)
Accretion expense(5) (3)
Other11
 (22)7
Decrease in Operating and maintenance expense$(594) $(747)$(121)
_________ 
(a)The financial results include Generation's acquisitionPrimarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek in the FitzPatrick nuclear generating station from March 31, 2017.third quarter of 2018.
(b)Primarily reflects decreased spending related to energy efficiency projects and decreased costs related to the saleabsence of Generation's electrical contracting businessa supplemental NEIL insurance distribution received in the first quarter 2018.
(c)Primarily reflects a decrease in the number of nuclear outage days.
(d)Primarily reflects the impact of a supplemental NEIL insurance distribution.
(e)Primarily reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities relateddue to the PHI and FitzPatrick acquisitionsbenefit recorded in 2017,2019 for the remeasurement of the TMI ARO and the PHI acquisitionincrease to materials and supplies inventory reserves in 2018.
(f)Primarily reflects one-time charges2018 associated with Generation’s decision to early retire the Oyster Creek nuclear facility in 2018 and the TMI nuclear facility in 2017.
(g)Primarily reflects charges to adjust the environmental reserve associated with Cotter.
(h)Primarily reflects charges to earnings related to the impairment of the EGTP assets held for sale in 2017, and in 2018 the impairment of certain wind projects at Generation.facility.
Depreciation and Amortization Expense
Depreciation and amortization expense for the three and six months ended June 30, 2018March 31, 2019 compared to the same period in 2017 increased2018 decreased primarily due to accelerated depreciation and amortization due to Generation's decision to early retire the permanent cease of generation operations at Oyster Creek in the third quarter of 2018.
Gain on Sales of Assets and TMI nuclear facilities.
Taxes Other Than Income
Taxes other than income, which can vary period to period, include non-income municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than incomeBusinesses for the three and six months ended June 30, 2018March 31, 2019 compared to the same period in 2017 remained relatively stable.2018 decreased primarily due to Generation's sale of its electrical contracting business in the first quarter of 2018.

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Gain on Sales of Assets and Businesses
Gain on sales of assets and businessesOther, net for the three and six months ended June 30, 2018March 31, 2019 compared to the same period in 20172018 increased primarily due to Generation's 2018 sale of its electrical contracting business.
Bargain Purchase Gain
Bargain purchase gain for the three and six months ended June 30, 2018 compared to the same period in 2017 decreased as a result of the gain associated with the FitzPatrick acquisition in 2017. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Interest Expense, Net
Interest expense, net for the three and six months ended June 30, 2018 compared to the same period in 2017 primarily reflects decreased interest expense due to the retirement of long-term debt.
Other, Net
Other, net for the three and six months ended June 30, 2018 compared to the same period in 2017 decreased primarily due to the change in the realized and unrealized gains and losses related to NDT funds of Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $3$(85) million and $92$(7) million for the three months ended June 30,March 31, 2019 and 2018, and 2017, respectively, and $(4) million and $37 million for the six months ended June 30, 2018 and 2017, respectively, related to the contractual elimination of income tax expense (benefit) associated with the NDT funds of the Regulatory Agreement Units. See Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information regarding NDT funds.
The following table provides unrealized and realized gains and losses(losses) on the NDT funds of the Non-Regulatory Agreement Units recognized in Other, net for the three and six months ended June 30, 2018 and 2017:Units:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2018 2017 2018 2017
Net unrealized (losses) gains on decommissioning trust funds$(120)
$70
 $(215) $235
Net realized gains on sale of decommissioning trust funds108
 40
 135
 49
 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
Equity in Losses of Unconsolidated Affiliates
Equity in losses of unconsolidated affiliates for the three and six months ended June 30, 2018 compared to the same period in 2017 remained relatively stable.
Effective Income Tax Rate
Generation's effective income tax rate was 11.0%rates were 34.3% and 39.5%4.5% for the three months ended June 30,March 31, 2019 and 2018, and 2017, respectively. Generation's effective income tax rate was 7.8% and (15.8)% for the six months ended June 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and six months ended June 30, 2018 compared to the same periods in 2017change is primarily related to an increase in qualified nuclear decommissioning trust fund income and a decrease in renewable tax savings due to the lower federal income tax rate as a result of the TCJA.credits. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information of the change in the effective income tax rate.information.

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ComEd

Results of Operations — ComEd
 Three Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 Six Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$1,398
 $1,357
 $41
 $2,910
 $2,656
 $254
Purchased power expense477
 378
 (99) 1,082
 713
 (369)
Revenues net of purchased power expense(a)(b)
921
 979
 (58) 1,828
 1,943
 (115)
Other operating expenses           
Operating and maintenance324
 377
 53
 638
 747
 109
Depreciation and amortization231
 211
 (20) 459
 419
 (40)
Taxes other than income79
 72
 (7) 156
 144
 (12)
Total other operating expenses634
 660
 26
 1,253
 1,310
 57
Gain on sales of assets1
 —
 1
 5
 —
 5
Operating income288
 319
 (31) 580
 633
 (53)
Other income and (deductions)           
Interest expense, net(85) (101) 16
 (175) (185) 10
Other, net4
 4
 —
 12
 8
 4
Total other income and (deductions)(81) (97) 16
 (163) (177) 14
Income before income taxes207
 222
 (15) 417
 456
 (39)
Income taxes43
 104
 61
 88
 197
 109
Net income$164
 $118
 $46
 $329
 $259
 $70
_________
(a)ComEd evaluates its operating performance using the measure of Revenue net of purchased power expense. ComEd believes that Revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of Revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
(b)For regulatory recovery mechanisms, including ComEd’s electric distribution and transmission formula rates, and riders, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).
Net Income
 Three Months Ended
March 31,		 
Favorable
(Unfavorable)
Variance
 2019 2018 
Operating revenues$1,408
 $1,512
 $(104)
Purchased power expense485
 605
 120
Revenues net of purchased power expense923
 907
 16
Other operating expenses     
Operating and maintenance321
 313
 (8)
Depreciation and amortization251
 228
 (23)
Taxes other than income78
 77
 (1)
Total other operating expenses650
 618
 (32)
Gain on sales of assets3
 3
 —
Operating income276
 292
 (16)
Other income and (deductions)     
Interest expense, net(87) (89) 2
Other, net8
 8
 —
Total other income and (deductions)(79) (81) 2
Income before income taxes197
 211
 (14)
Income taxes40
 46
 6
Net income$157
 $165
 $(8)
Three Months Ended June 30, 2018March 31, 2019 Compared to Three Months Ended June 30, 2017.March 31, 2018.Net income ComEd’s Net incomeremained relatively consistent for the three months ended June 30, 2018 was higher thanMarch 31, 2019 as compared to the same period in 2017 primarily due to higher electric distribution and energy efficiency formula rate earnings as well as additional tax and interest recorded in the second quarter of 2017 relating to Exelon's like-kind exchange tax position. The TCJA did not significantly impact ComEd's net income for the three months ended June 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.2018.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017. ComEd’s Net income for the six months ended June 30, 2018 was higher than the same period in 2017 primarily due to higher electric distribution and energy efficiency formula rate earnings as well as additional tax

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and interest recorded in the second quarter of 2017 relating to Exelon's like-kind exchange tax position. The TCJA did not significantly impact ComEd's net income for the six months ended June 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Revenues Net of Purchased Power Expense
Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC, and ZEC procurement costs and participation in customer choice programs. ComEd is permitted to recoverrecovers electricity, REC, and ZEC procurement costs from retail customers without mark-up. Therefore, fluctuations in these costs have no impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Exelon 2017 Form 10-K for additional information on ComEd’s electricity procurement process.RNF.
All ComEd customersCustomers have the choice to purchase electricity from a competitive electric generation supplier.suppliers. Customer choice programs do not impact ComEd’sthe volume of deliveries but do affect ComEd’simpact Operating revenues related to supplied energy, which is fully offsetelectricity.
The changes in Purchased power expense. Therefore, customer choice programs have no impact on Revenue net of purchased power expense.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and six months ended June 30, 2018 and 2017,RNF consisted of the following:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2018 2017 2018 2017
Electric70% 71% 69% 71%
Retail customers purchasing electric generation from competitive electric generation suppliers at June 30, 2018 and 2017 consisted of the following:
 June 30, 2018 June 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric1,337,900
 33% 1,382,600
 35%
The changes in ComEd’s Revenue net of purchased power expense for the three and six months ended June 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018
 Increase (Decrease) Increase (Decrease)
Electric distribution revenue$(35) $(67)
Transmission revenue(9) (15)
Energy efficiency revenue(a)
10
 17
Regulatory required programs(a)
(37) (94)
Uncollectible accounts recovery, net1
 3
Other12
 41
Total decrease$(58) $(115)
_________
(a)Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

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 Three Months Ended
March 31, 2019
 Increase (Decrease)
Electric distribution$25
Transmission9
Energy efficiency13
Uncollectible accounts recovery, net—
Other(31)
Total increase$16
Revenue Decoupling. The demand for electricity is affected by weather conditions. Under FEJA, ComEd revised itsconditions 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 formula effective January 1, 2017pursuant to eliminate the favorable and unfavorable impacts on Operating revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer.FEJA.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in ComEd's service territory with cooling degree-days generally having a more significant impact to ComEd, particularly during the summer months. The changes in heating and cooling degree-days in ComEd’s service territory for the three and six months ended June 30, 2018 and 2017, consisted
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ComEd
Heating and Cooling Degree-Days      % Change
Three Months Ended June 30,2018 2017 Normal2018 vs. 2017 2018 vs. Normal
Heating Degree-Days820
 577
 734
 42.1% 11.7%
Cooling Degree-Days364
 263
 241
 38.4% 51.0%
          
Six Months Ended June 30,         
Heating Degree-Days3,937
 3,227
 3,875
 22.0% 1.6%
Cooling Degree-Days364
 263
 241
 38.4% 51.0%

Electric Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. In addition, ComEd's allowed ROE is subject to reduction if ComEd does not deliver the reliability and customer service benefits to which it has committed over the ten-year life of the investment program. Electric distribution revenue decreasedincreased during the three and six months ended June 30,March 31, 2019 as compared to the same period in 2018, primarily due to the impact of the lower federal income tax rate, partially offset by increased revenues due to higher rate base and increased operating and maintenance and depreciation expense as compared to the same period in 2017.expenses. See Operating and maintenance and Depreciation and amortization expense discussions below and Note 6 — Regulatory Matters and Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.Matters.
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. ForTransmission revenue increased for the three and six months ended June 30, 2018, ComEd recorded decreased transmission revenue primarily due to the decreased peak load, partially offset by increased revenues due to higher rate base and increased depreciation expenseMarch 31, 2019 as compared to the same period in 2017.2018, primarily due to the increased peak load and higher rate base. See Operating and maintenance expense below and Note 6 — Regulatory Matters and Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue. Beginning June 1, 2017, FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ComEd’s allowed ROE isEnergy efficiency revenue increased during the annual averagethree months ended March 31, 2019 as compared to the same period in 2018, primarily due to the impact of higher rate on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE is

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subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal.base. See Depreciation and amortization expense discussions below and Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs. This represents the change in Operating revenues collected under approved rate riders to recover costs incurred for regulatory programs such as ComEd’s purchased power administrative costs and energy efficiency and demand response through June 1, 2017 pursuant to FEJA. The riders are designed to provide full and current cost recovery. An equal and offsetting amount has been included in Operating and maintenance expense. See Operating and maintenance expense discussion below for additional information on included programs.
Uncollectible Accounts Recovery, Net.Net Uncollectible accounts recovery, net represents recoveries under ComEd’sthe uncollectible accounts tariff. See Operating and maintenance expense discussion below for additional information on this tariff.
Other.Other revenue which can vary period to period,, includes rental revenue, revenue related to late payment charges, assistance provided to other utilities through mutual assistance programs,revenues, and recoveries of environmental costs associated with MGP sites, and recoveries of energy procurement costs.sites. The increasedecrease in Other revenue for the three and six months ended June 30, 2018March 31, 2019 as compared to the same period in 20172018 primarily reflects absence of mutual assistance revenues associated with hurricane and winter storm restoration efforts.efforts that occurred in Q1 2018. An equal and offsetting amount has beenwas included in Operating and maintenance expense and Taxes other than income.
See Note 18 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The increase in Operating and Maintenance Expensemaintenance expense consisted of the following:
 Three Months Ended
June 30,		 
Increase
(Decrease)
 Six Months Ended
June 30,		 Increase (Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense — baseline$318
 $334
 $(16) $630
 $645
 $(15)
Operating and maintenance expense — regulatory required programs(a)
6
 43
 $(37) 8
 102
 (94)
Total Operating and maintenance expense$324

$377

$(53)
$638

$747

$(109)
 Three Months Ended
March 31, 2019
 Increase (Decrease)
Baseline 
Labor, other benefits, contracting and materials(a)
$(6)
Pension and non-pension postretirement benefits expense(b)
(11)
Storm-related costs18
BSC costs(a)
2
Other(a)
5
Total increase$8
_________
(a)Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates.Reflects absence of mutual assistance expenses. An equal and offsetting amount has been reflected in Operating revenues.

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The decrease in Operating and maintenance expense for the three and six months ended June 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor, other benefits, contracting and materials(a)
$(11) $(1)
Pension and non-pension postretirement benefits expense(a)
(1) —
Storm-related costs(10) (17)
Uncollectible accounts expense — provision(b)
1
 4
Uncollectible accounts expense — recovery, net(b)
—
 (1)
BSC costs(a)
4
 2
Other(a)
1
 (2)
 (16) (15)
Regulatory required programs   
Energy efficiency and demand response programs(c)
(37) (94)
Decrease in operating and maintenance expense$(53) $(109)
_________
(a)Includes additional costs associated with mutual assistance programs. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
(b)ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expensePrimarily reflects an increase in discount rates and the amounts collected in rates annually through a rider mechanism. During the three and six months ended June 30, 2018, ComEd recorded a net increase in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
(c)Beginning June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful lifefavorable impacts of the related energy efficiency measures.merger of two of Exelon’s pension plans effective in January 2019, partially offset by lower than expected asset returns in 2018.
Depreciation and Amortization Expense
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ComEd

The increase in Depreciation and amortization expense during the three and six months ended June 30, 2018 compared to the same period in 2017, consisted of the following:
Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018		Three Months Ended
March 31, 2019
Increase IncreaseIncrease (Decrease)
Depreciation expense(a)
$10
 $21
Depreciation and amortization(a)
$18
Regulatory asset amortization(b)
10
 19
5
Total increase$20
 $40
$23
_________
(a)Primarily reflectsReflects ongoing capital expenditures for the three and six months ended June 30, 2018.higher depreciation rates effective January 2019.
(b)Beginning in June 2017, includesIncludes amortization of ComEd's energy efficiency formula rate regulatory asset.
Taxes Other Than Income
Taxes other than income, which can vary year to year, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income taxes remained relatively consistent for the three and six months ended June 30, 2018 compared to the same period in 2017.

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Gain on Sales of Assets
The increase in Gain on sales of assets during the three and six months ended June 30, 2018 compared to the same period in 2017, is primarily due to the sale of land in March 2018.
Interest Expense, Net
The changes in Interest expense, net, for the three and six months ended June 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018
 Increase (Decrease) Increase (Decrease)
Interest expense related to uncertain tax positions(a)
$(14) $(14)
Interest expense on debt (including financing trusts)—
 4
Other(2) —
Decrease in interest expense, net$(16) $(10)
__________
(a)Primarily reflects additional interest recorded in the second quarter of 2017 related to Exelon's like-kind exchange tax position.
Other, Net
Other, net, remained relatively consistent for the three and six months ended June 30, 2018 compared to the same period in 2017.
Effective Income Tax Rate
ComEd's effective income tax rate was 20.8%20.3% and 46.8%21.8% for the three months ended June 30,March 31, 2019 and 2018, and 2017, respectively. ComEd's effective income tax rate was 21.1% and 43.2% for the six months ended June 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and six months ended June 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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ComEd Electric Operating Statistics Detail
Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		 % Change 
Weather-
Normal
% Change
 Six Months Ended
June 30,		 % Change 
Weather-
Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential6,557
 5,919
 10.8% 1.5% 13,173
 12,160
 8.3% 1.2%
Small commercial & industrial7,735
 7,437
 4.0% 1.7% 15,578
 15,146
 2.9% 0.6%
Large commercial & industrial7,111
 6,798
 4.6% 3.2% 13,948
 13,480
 3.5% 2.0%
Public authorities & electric railroads286
 282
 1.4% 1.2% 646
 625
 3.4% 2.1%
Total retail deliveries21,689

20,436
 6.1% 2.1% 43,345

41,411
 4.7% 1.2%
 As of June 30,
Number of Electric Customers2018 2017
Residential3,631,213
 3,605,731
Small commercial & industrial379,862
 375,976
Large commercial & industrial2,002
 2,009
Public authorities & electric railroads4,776
 4,785
Total4,017,853

3,988,501
_________
(a)Reflects delivery volume from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier, as all customers are assessed delivery charges.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

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Results of Operations — PECO
 Three Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 Six Months Ended
June 30,		 Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$653
 $630
 $23
 $1,518
 $1,426
 $92
Purchased power and fuel expense222
 197
 (25) 555
 484
 (71)
Revenues net of purchased power and fuel expense(a)
431
 433
 (2) 963
 942
 21
Other operating expenses           
Operating and maintenance191
 190
 (1) 466
 398
 (68)
Depreciation and amortization74
 71
 (3) 149
 141
 (8)
Taxes other than income39
 35
 (4) 79
 74
 (5)
Total other operating expenses304
 296
 (8) 694
 613
 (81)
Operating income127
 137
 (10) 269
 329
 (60)
Other income and (deductions)           
Interest expense, net(32) (31) (1) (64) (62) (2)
Other, net—
 2
 (2) 2
 3
 (1)
Total other income and (deductions)(32) (29) (3) (62) (59) (3)
Income before income taxes95
 108
 (13) 207
 270
 (63)
Income taxes(1) 20
 21
 (3) 55
 58
Net income$96
 $88
 $8
 $210
 $215
 $(5)
_________
(a)PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense and revenue net of fuel expense figures are not presentations defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.
Net Income
 Three Months Ended
March 31,		 
Favorable
(Unfavorable)
Variance
 2019 2018 
Operating revenues$900
 $866
 $34
Purchased power and fuel expense331
 333
 2
Revenues net of purchased power and fuel expense569
 533
 36
Other operating expenses     
Operating and maintenance225
 275
 50
Depreciation and amortization81
 75
 (6)
Taxes other than income41
 41
 —
Total other operating expenses347
 391
 44
Operating income222
 142
 80
Other income and (deductions)     
Interest expense, net(33) (33) —
Other, net4
 2
 2
Total other income and (deductions)(29) (31) 2
Income before income taxes193
 111
 82
Income taxes25
 (2) (27)
Net income$168
 $113
 $55
Three Months Ended June 30, 2018March 31, 2019 Compared to Three Months Ended June 30, 2017.March 31, 2018. PECO's Net income increased from the same period in 2017,by $55 million primarily due to lower storm costs, higher Operating revenues net of purchase power and fuel expense attributable to favorable weather and volume. The TCJA did not significantly impact PECO's Net income for the three and six months ended June 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the requirement to pass back the tax savings through customer rates.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017.PECO's Net income decreased from the same period in 2017, primarily due to higher Operating and maintenance expense attributable to increased storm restoration costselectric distribution rates as a result of winter storms in Marchthe 2018 partially offset byelectric rate case settlement and higher Operating revenues net of purchase power and fuel expense attributable to favorable weather and volume. The TCJA did not significantly impact PECO's Net income for the three and six months ended June 30, 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the requirement to pass back the tax savings through customergas distribution rates.

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Revenues Net of Purchased Power and Fuel Expense
Electric and natural gas revenue and purchasedThere are certain drivers of Operating revenues that are fully offset by their impact on Purchased power and fuel expense are affected by fluctuationssuch as commodity and REC procurement costs and participation in commodity procurement costs. PECO's electric supply and natural gas cost rates charged to customers are subject to adjustments as specified in the PAPUC-approved tariffs that are designed to recover or refund the difference between the actual cost of electric supply andcustomer choice programs. PECO recovers electricity, natural gas and the amount included in rates in accordance with PECO's GSA and PGC, respectively.REC procurement costs from customers without mark-up. Therefore, fluctuations in electric supply and natural gas procurementthese costs have no impact on electric and natural gas revenue net of purchased power and fuel expense.RNF.
Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All PECO customersCustomers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customer's Choice of suppliers doessuppliers. Customer choice programs do not impact the volume of deliveries or RNF, but affects revenue collected from customersimpact Operating revenues related to supplied energyelectricity and natural gas service. Customer choice program activity has no impact on electric and natural gas revenues net of purchased power and fuel expense.gas.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and six months ended June 30, 2018 and 2017,The changes in RNF consisted of the following:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2018 2017 2018 2017
Electric71% 73% 69% 71%
Natural Gas28% 29% 25% 26%
 Three Months Ended
March 31, 2019
 Increase (Decrease)
 Electric Gas Total
Weather$—
 $2
 $2
Volume1
 1
 2
Pricing14
 10
 24
Regulatory required programs10
 4
 14
Other(7) 1
 (6)
Total increase$18
 $18
 $36
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at June 30, 2018 and 2017 consisted of the following:
156
 June 30, 2018 June 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric547,800
 33% 581,600
 36%
Natural Gas85,700
 16% 82,000
 16%

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PECO

The changes in PECO’s Operating revenues net of purchased power and fuel expense for the three and six months ended June 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018
 Increase (Decrease) Increase (Decrease)
 Electric Natural Gas Total Electric Natural Gas Total
Weather$2
 $6
 $8
 $19
 $18
 $37
Volume9
 —
 9
 8
 3
 11
Pricing(23) (1) (24) (30) (8) (38)
Regulatory required programs—
 —
 —
 (2) —
 (2)
Other7
 (2) 5
 16
 (3) 13
Total (decrease) increase$(5) $3
 $(2) $11
 $10
 $21
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 six months ended June 30, 2018March 31, 2019 compared to the same period in 2017, Operating revenue net of purchased power and fuel2018, RNF increased slightly due to favorable weather conditions.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and six months ended June 30, 2018March 31, 2019 compared to the same period in 20172018 and normal weather consisted of the following:
Heating and Cooling Degree-Days  Normal % Change  Normal % Change
Three Months Ended June 30,2018 2017From 2017 2018 vs. Normal
Three Months Ended March 31,2019 2018 Normal From 2018 2019 vs. Normal
Heating Degree-Days482
 329
 441
 46.5 % 9.3 %2,432
 2,397
1.5% 0.1%
Cooling Degree-Days382
 415
 383
 (8.0)% (0.3)%2
 —
 1
 200.0% 100.0%
         
Six Months Ended June 30,         
Heating Degree-Days2,879
 2,423
 2,885
 18.8 % (0.2)%
Cooling Degree-Days382
 415
 385
 (8.0)% (0.8)%
Volume. Operating revenue net of purchased power related to deliveryElectric volume, exclusive of the effects of weather, for the three and six months ended June 30, 2018March 31, 2019 compared to the same period in 2017,2018, increased due to the impact of moderate economic and customer growth partially offset by the impact of energy efficiency initiatives on customer usages primarily in the residential class. Additionally, the increase represents a shift in the volume profile across classes from the commercial and industrial classes to the residential class.  Operating revenue net of fuel expenseNatural gas volume for the sixthree months ended June 30, 2018March 31, 2019, compared to the same period in 20172018, increased due to strong customer growth and moderate economic growth.
Electric Retail Deliveries to Customers (in GWhs)Three Months Ended
March 31,		 % Change 
Weather -
Normal
% Change(b)
2019 2018 
Residential3,641
 3,628
 0.4 % 0.4 %
Small commercial & industrial2,066
 2,029
 1.8 % 1.8 %
Large commercial & industrial3,571
 3,703
 (3.6)% (3.6)%
Public authorities & electric railroads195
 197
 (1.0)% (0.9)%
Total electric retail deliveries(a)
9,473
 9,557
 (0.9)% (0.9)%
 As of March 31,
Number of Electric Customers2019 2018
Residential1,485,698
 1,474,555
Small commercial & industrial153,042
 151,947
Large commercial & industrial3,107
 3,113
Public authorities & electric railroads9,638
 9,541
Total1,651,485
 1,639,156
_________
(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

 As of March 31,
Number of Natural Gas Customers2019 2018
Residential483,560
 478,565
Small commercial & industrial44,274
 44,053
Large commercial & industrial1
 4
Transportation744
 768
Total528,579
 523,390
_________
(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)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing.Pricing Operating revenues net of purchased power as a result of pricing for the three and six months ended June 30, 2018March 31, 2019 compared to the same period in 2017 decreased2018 increased primarily due to the pass

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back through customersan increase in electric distribution rates the tax savings associatedcharged to customers.  The increase in electric distribution rates was effective January 1, 2019 in accordance with the lower federal income tax rate.2018 PAPUC approved electric distribution rate case settlement. Additionally, the increase represents revenue from higher gas distribution rates. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs.Programs This represents the change in Operating revenues collected under approved riders to recover costs incurred for regulatory programs such as smart meter, energy efficiency and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Income taxes. See Operating and maintenance expense discussion below for additional information on included programs.
Other. Other revenue which can vary period to period, primarily includes wholesale transmission revenue, rental revenue, revenue related to late payment charges, and assistance provided to other utilities through mutual assistance programs.revenues and wholesale transmission revenue.
Operating and Maintenance ExpenseSee Note 18— Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
 Three Months Ended
June 30,		 
Increase
(Decrease)
 Six Months Ended
June 30,		 Increase
(Decrease)
 2018 2017  2018 2017��
Operating and maintenance expense — baseline$175
 $174
 $1
 $435
 $370
 $65
Operating and maintenance expense — regulatory required programs(a)
16
 16
 —
 31
 28
 3
Total Operating and maintenance expense$191
 $190
 $1
 $466
 $398
 $68
_________
(a)Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
The changes in Operating and maintenance expense for the three and six months ended June 30, 2018 compared to the same period in 2017, consisted of the following:
Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018		Three Months Ended
March 31, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease)
Baseline    
Labor, other benefits, contracting and materials$7
 $11
$7
Storm-related costs(a)
—
 58
(56)
Pension and non-pension postretirement benefits expense(2) (3)(2)
BSC costs3
Other(4) (1)(1)
1
 65
(49)
Regulatory Required Programs    
Energy efficiency—
 3
(1)
Total increase$1
 $68
Total decrease$(50)
__________
(a)Reflects increaseddecreased storm costs incurred fromdue to the Q1March 2018 winter storms.

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PECO

Depreciation and Amortization Expense
The changes in Depreciation and amortization expense increased primarily due to ongoing capital spend forconsisted of the three and six months ended June 30, 2018 compared to the same period in 2017.following:
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income increased for the three and six months ended June 30, 2018 compared to the same period in 2017 due to an increase in gross receipts tax driven by an increase in electric revenue.
 Three Months Ended March 31, 2019
 Increase (Decrease)
Depreciation and amortization(a)
$5
Regulatory asset amortization1
Total increase$6
Interest Expense, Net__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net for the three and six months ended June 30, 2018 remained relatively consistent compared to the same period in 2017.
Other, Net
Other, net for the three and six months ended June 30, 2018 remained consistent compared to the same period in 2017.
Effective Income Tax Rate
PECO's effective income tax rate was (1.1)%Rates were 13.0% and 18.5%(1.8)% for the three months ended June 30,March 31, 2019 and 2018, and 2017, respectively. PECO's effective income tax rate was (1.4)% and 20.4% for the six months ended June 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and six months ended June 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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BGE

PECO Electric Operating Statistics
Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		 % Change 
Weather -
Normal
% Change
 Six Months Ended
June 30,		 % Change Weather -
Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential2,946
 2,809
 4.9 % 3.8 % 6,574
 6,187
 6.3 % 1.7 %
Small commercial & industrial1,930
 1,914
 0.8 % 0.4 % 3,958
 3,890
 1.7 % (0.4)%
Large commercial & industrial3,811
 3,830
 (0.5)% 0.1 % 7,514
 7,456
 0.8 % 1.1 %
Public authorities & electric railroads182
 196
 (7.1)% (5.6)% 379
 420
 (9.8)% (9.1)%
Total retail deliveries8,869

8,749
 1.4 % 1.2 % 18,425

17,953
 2.6 % 0.8 %
 As of June 30,
Number of Electric Customers2018 2017
Residential1,474,901
 1,461,931
Small commercial & industrial152,152
 150,783
Large commercial & industrial3,114
 3,105
Public authorities & electric railroads9,544
 9,795
Total1,639,711
 1,625,614
_________
(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.

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PECO Natural Gas Operating Statistics
Deliveries to Customers (in mmcf)Three Months Ended
June 30,		 % Change 
Weather -
 Normal
% Change
 Six Months Ended
June 30,		 % Change 
Weather -
 Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential5,889
 4,577
 28.7% 0.9% 26,463
 22,689
 16.6% 0.9 %
Small commercial & industrial3,598
 3,039
 18.4% 0.2% 14,016
 12,130
 15.5% 2.2 %
Large commercial & industrial6
 5
 20.0% 12.8% 52
 13
 300.0% 291.0 %
Transportation5,981
 5,759
 3.9% 3.2% 13,549
 13,448
 0.8% (3.3)%
Total natural gas deliveries15,474
 13,380
 15.7% 1.6% 54,080
 48,280
 12.0% 0.2 %
 As of June 30,
Number of Natural Gas Customers2018 2017
Residential478,954
 474,360
Small commercial & industrial43,748
 43,400
Large commercial & industrial1
 4
Transportation767
 768
Total523,470

518,532
_________
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

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Results of Operations — BGE
 Three Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 Six Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$662
 $674
 $(12) $1,639
 $1,625
 $14
Purchased power and fuel expense229
 234
 5
 609
 584
 (25)
Revenues net of purchased power and fuel expense(a)
433
 440
 (7) 1,030
 1,041
 (11)
Other operating expenses           
Operating and maintenance176
 174
 (2) 397
 357
 (40)
Depreciation and amortization114
 112
 (2) 248
 239
 (9)
Taxes other than income59
 56
 (3) 124
 119
 (5)
Total other operating expenses349
 342
 (7) 769
 715
 (54)
Gain on sales of assets1
 —
 1
 1
 —
 1
Operating income85
 98
 (13) 262
 326
 (64)
Other income and (deductions)           
Interest expense, net(25) (26) 1
 (51) (54) 3
Other, net4
 4
 —
 9
 8
 1
Total other income and (deductions)(21) (22) 1
 (42) (46) 4
Income before income taxes64
 76
 (12) 220
 280
 (60)
Income taxes13
 31
 18
 41
 111
 70
Net income$51
 $45
 $6
 $179
 $169
 $10
_________
(a)BGE evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. BGE believes revenues net of purchased power and fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenues net of purchased power and fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.
Net Income
 Three Months Ended
March 31,		 
Favorable
(Unfavorable)
Variance
 2019 2018 
Operating revenues$976
 $977
 $(1)
Purchased power and fuel expense360
 380
 20
Revenues net of purchased power and fuel expense616
 597
 19
Other operating expenses     
Operating and maintenance192
 221
 29
Depreciation and amortization136
 134
 (2)
Taxes other than income68
 65
 (3)
Total other operating expenses396
 420
 24
Operating income220
 177
 43
Other income and (deductions)     
Interest expense, net(29) (25) (4)
Other, net5
 4
 1
Total other income and (deductions)(24) (21) (3)
Income before income taxes196
 156
 40
Income taxes36
 28
 (8)
Net income$160
 $128
 $32
Three Months Ended June 30, 2018March 31, 2019 Compared to Three Months Ended June 30, 2017March 31, 2018.. BGE’s Net income for the three months ended June 30, 2018 was higher than the same period in 2017,increased by $32 million primarily due to higher transmission revenues. The TCJA did not significantly impact BGE's net income for the three months ended June 30, 2018 as the favorable income tax impacts were predominantly offset bygas distribution rates and lower revenues resulting from the pass back of the tax savings through customer rates.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017. BGE’s Net income for the six months ended June 30, 2018 was higher than the same period in 2017, due primarily to higher transmission revenues,storm costs, partially offset by an increase in Operating and maintenancehigher interest expense attributabledue to increased storm restoration costs as a result of winter storms in March 2018. The TCJA did not significantly impact BGE's net income for the six months ended June 30,September 2018 as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.debt issuance.

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Revenues Net of Purchased Power and Fuel Expense
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 programs allowing customers to select a competitive electric or natural gas supplier. Operating revenues and Purchased power and fuel expense are affected by fluctuationsparticipation in commodity procurement costs. BGE’s electric and natural gas rates charged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric power and purchasedcustomer choice programs. BGE recovers electricity, natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs, respectively.procurement costs from customers without mark-up. Therefore, fluctuations in electric supply and natural gas procurementthese costs have no impact on Revenues net of purchased power and fuel expense.RNF.
Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in the number of customers electing to use a competitive supplier for electricity and/or natural gas. All BGE customersCustomers have the choice to purchase electricity and natural gas from electric generation and natural gas competitive suppliers. The customers'Customer choice of suppliers doesprograms do not impact the volume of deliveries or RNF but does affect revenue collected from customersimpact Operating revenues related to supplied electricity and natural gas.
Retail deliveries purchased from competitive electricity and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and six months ended June 30, 2018 and 2017The changes in RNF consisted of the following:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2018 2017 2018 2017
Electric61% 62% 59% 60%
Natural Gas66% 68% 52% 53%
The number of retail customers purchasing electricity and natural gas from competitive suppliers at June 30, 2018 and 2017 consisted of the following:
 June 30, 2018 June 30, 2017
 Number of Customers % of total retail customers Number of customers % of total retail customers
Electric337,200
 26% 340,500
 27%
Natural Gas148,800
 22% 150,400
 22%

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The changes in BGE’s Operating revenues net of purchased power and fuel expense for the three and six months ended June 30, 2018, compared to the same period in 2017, consisted of the following:
 Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018
 Increase (Decrease) Increase (Decrease)
 Electric Gas Total Electric Gas Total
Distribution revenue$(15) $(3) $(18) $(34) $(17) $(51)
Regulatory required programs—
 1
 1
 4
 3
 7
Transmission revenue6
 —
 6
 20
 —
 20
Other, net1
 3
 4
 3
 10
 13
Total (decrease) increase$(8) $1
 $(7) $(7) $(4) $(11)
 Three Months Ended
March 31, 2019
 Increase (Decrease)
 Electric Gas Total
Distribution$4
 $31
 $35
Regulatory required programs(2) (3) (5)
Transmission(6) —
 (6)
Other, net(4) (1) (5)
Total increase (decrease)$(8) $27
 $19
Revenue Decoupling.The demand for electricity and natural gas is affected by weather and usage conditions. The MDPSC allows BGE to record a monthly adjustment to its electric and natural gas distribution revenue from all residential customers, commercial electric customers, the majority of large industrial electric customers, and all firm service natural gas customers to eliminate the effect ofcustomer usage. However, Operating revenues are not impacted by abnormal weather andor usage patterns per customer on BGE's electric and natural gasas a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution volumes, thereby recovering a specified dollar amount of distribution revenuecharge per customer by customer class, regardless of fluctuations in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved distribution chargesclass. While Operating revenues are not impacted by abnormal weather or usage per customer, regardless of what BGE's actual distribution volumes were for a billing period. Therefore, while this revenue is affectedthey are impacted by customer growth (i.e., increasechanges in the number of customers), it will not be affected by volatility in actual weather or usage conditions (i.e., changes in consumption per customer). BGE bills or credits customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.customers.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in BGE's service territory. The changes in heating and cooling degree-days in BGE's service territory
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BGE


 As of March 31,
Number of Electric Customers2019 2018
Residential1,171,027
 1,163,887
Small commercial & industrial113,976
 113,675
Large commercial & industrial12,278
 12,148
Public authorities & electric railroads266
 270
Total1,297,547
 1,289,980
 As of March 31,
Number of Gas Customers2019 2018
Residential635,241
 631,594
Small commercial & industrial38,322
 38,443
Large commercial & industrial5,981
 5,874
Total679,544
 675,911
Distribution Revenue increased for the three and six months ended June 30, 2018March 31, 2019, compared to the same period in 2017 consisted of the following:
Heating and Cooling Degree-Days      % Change
Three Months Ended June 30,2018 2017 Normal 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days498
 397
 507
 25.4% (1.8)%
Cooling Degree-Days299
 283
 256
 5.7% 16.8 %
          
Six Months Ended June 30,         
Heating Degree-Days2,939
 2,460
 2,898
 19.5% 1.4 %
Cooling Degree-Days299
 283
 256
 5.7% 16.8 %
Distribution Revenue. The decrease in distribution revenues for the three and six months ended June 30, 2018, compared to the same period in 2017, was primarily due to the impact of reducedhigher gas distribution rates to reflect the lower federal income tax rate.that became effective in January 2019. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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Regulatory Required Programs.Programs Revenue from regulatory required programs are billingsrepresent revenues collected under approved riders to recover costs incurred for the costs of various legislative and/or regulatory programs that are recoverable from customers on a fullsuch as conservation, demand response, STRIDE, and current basis. These programsthe 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 in BGE's Consolidated Statements of Operations and Comprehensive Income.income.
Transmission Revenue.Under a FERC approved formula, transmission revenue varies from year to year based upon rate adjustments to reflect fluctuations in the underlying costs, capital investments being recovered and other billing determinants. The increasethe 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 six months ended June 30, 2018,March 31, 2019, compared to the same period in 2017, was primarily due to increases in capital investment and operating and maintenance expense recoveries.2018. See Operating and Maintenance Expense below and Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other Net. revenueOther, netincludes revenue which can vary from periodrelated to period, primarily includes assistance provided to other utilities through BGE's mutual assistance program, off-system sales, and other miscellaneous revenue such as service application fees, andmutual assistance revenues, late payment fees.charges, and off-system sales.
Operating and Maintenance ExpenseSee 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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 Three Months Ended
June 30,		 
Increase
(Decrease)
 Six Months Ended
June 30,		 Increase
(Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense — baseline$174
 $170
 $4
 $392
 $348
 $44
Operating and maintenance expense — regulatory required programs(a)
2
 4
 (2) 5
 9
 (4)
Total Operating and maintenance expense$176
 $174
 $2
 $397
 $357
 $40
_________
(a)Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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BGE


The changes in Operating and maintenance expense for the three and six months ended June 30, 2018, compared to the same period in 2017, consisted of the following:
Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018		Three Months Ended
March 31, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease)
Baseline    
Storm-related costs(a)
$(4) $23
$(28)
Labor, other benefits, contracting and materials3
 7
Uncollectible accounts expense(1) 2
BSC costs3
 4
2
Other3
 8
(2)
4
 44
(28)
Regulatory Required Programs    
Other(2) (4)(1)
Total increase$2
 $40
Total decrease$(29)
__________
(a)Reflects increaseddecreased storm restoration costs incurred fromdue to the Q1March 2018 winter storms.
Depreciation and Amortization
The changes in Depreciation and amortization expense for the three and six months ended June 30, 2018, compared to the same period in 2017 consisted of the following:
Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018		Three Months Ended
March 31, 2019
Increase (Decrease) Increase (Decrease)Increase (Decrease)
Depreciation expense(a)
$7
 $9
Depreciation and amortization(a)
$5
Regulatory asset amortization(b)
(8) (11)1
Regulatory required programs(c)
3
 11
(4)
Total increase$2
 $9
$2
_________
(a)Depreciation expenseand amortization increased primarily due to ongoing capital expenditures.
Effective income tax rateswere 18.4% and 17.9% for the three months ended March 31, 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
 2019 2018 
PHI$117
 $65
 $52
Pepco55
 31
 24
DPL53
 31
 22
ACE10
 7
 3
Other(a)
(1) (4) 3
_________
(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, 2019 Compared to Three Months Ended March 31, 2018. Net Income increased by $52 million primarily due to higher distribution and transmission base rates, lower uncollectible accounts expense, lower storm costs, and the absence of a write-off of construction work in progress.

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Pepco


Results of Operations — Pepco
 Three Months Ended March 31, Favorable (Unfavorable) Variance
2019 2018 
Operating revenues$575
 $557
 $18
Purchased power expense187
 182
 (5)
Revenues net of purchased power expense388
 375
 13
Other operating expenses     
Operating and maintenance118
 130
 12
Depreciation and amortization94
 96
 2
Taxes other than income92
 93
 1
Total other operating expenses304
 319
 15
Operating income84
 56
 28
Other income and (deductions)    
Interest expense, net(34) (31) (3)
Other, net7
 8
 (1)
Total other income and (deductions)(27) (23) (4)
Income before income taxes57
 33
 24
Income taxes2
 2
 —
Net income$55
 $31
 $24
Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018.Net income increased by $24 million primarily due to higher electric distribution base rates in Maryland that became effective June 2018, higher electric distribution base rates in the District of Columbia that became effective August 2018, an increase in the Network Transmission Service rate that became effective June 2018, an increase in the highest daily peak load, and lower storm costs.
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity and REC procurement costs and participation in customer choice programs. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity.
The changes in RNF consisted of the following:
 Three Months Ended March 31, 2019
 Increase (Decrease)
Volume$4
Distribution6
Regulatory required programs(10)
Transmission13
Total increase$13
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 months ended March 31, 2019 compared to the same period in 2018, primarily due to the impact of residential customer growth.
 As of March 31,
Number of Electric Customers2019 2018
Residential809,845
 797,105
Small commercial & industrial54,295
 53,602
Large commercial & industrial22,030
 21,718
Public authorities & electric railroads153
 146
Total886,323
 872,571
Distribution Revenues increased for the three months ended March 31, 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 June 2018 and higher electric distribution base rates charged to customers in the District of Columbia that became effective in August 2018. 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 months ended March 31, 2019 compared to the same period in 2018 primarily due to an increase in the Network Transmission Service rate that became effective June 2018 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 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, 2019
 Increase (Decrease)
Baseline 
Labor, other benefits, contracting and materials$(5)
Pension and non-pension postretirement benefits expense1
Uncollectible accounts expense(2)
Storm-related costs(3)
BSC and PHISCO costs(3)
Other(1)
 (13)
  
Regulatory required programs1
Total decrease$(12)
The changes in Depreciation and amortization expense consisted of the following:
 Three Months Ended March 31, 2019
 Increase (Decrease)
Depreciation and amortization(a)
$5
Regulatory required programs(b)
(7)
Total decrease$(2)
_________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b)Regulatory asset amortization decreased for the three and six months ended June 30, 2018 compared to the same period in 2017 primarily due to certain regulatory assets that became fully amortized as of December 31, 2017. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(c)Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
Taxes Other Than Income
Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and six months ended June 30, 2018, compared to the same period in 2017, increased primarily due to an increase in property taxes.
Gain on Sales of Assets
The increase in Gain on sales of assets during the three and six months ended June 30, 2018, compared to the same period in 2017, is primarily due to the sale of land in June 2018.

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Interest Expense, Net
Interest expense, net for the three and six months ended June 30, 2018, compared to the same period in 2017, remained relatively consistent.
Other, Net
Other, net for the three and six months ended June 30, 2018, compared to the same period in 2017, remained relatively consistent.
Effective Income Tax Rate
BGE’s effective income tax rate was 20.3%rates were 3.5% and 40.8%6.1% for the three months ended June 30,March 31, 2019 and 2018, and 2017, respectively. BGE's effective income tax rate was 18.6% and 39.6% for the six months ended June 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three and six months ended June 30, 2018, compared to the same periods in 2017, is primarily due tothe lower federalaccelerated amortization of certain deferred income tax rateregulatory liabilities established upon the enactment of TCJA as athe result of the TCJA.regulatory settlements. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
BGE Electric Operating Statistics and Detail
Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		 % Change Weather -
Normal
% Change		 Six Months Ended
June 30,		 % Change Weather -
Normal
% Change
2018
2017  2018 2017 
Retail Deliveries(a)
               
Residential2,717
 2,629
 3.3 % 0.9 % 6,297
 5,756
 9.4 % 2.2 %
Small commercial & industrial700
 677
 3.4 % (3.4)% 1,485
 1,425
 4.2 % (0.4)%
Large commercial & industrial3,396
 3,373
 0.7 % (1.9)% 6,752
 6,641
 1.7 % (0.7)%
Public authorities & electric railroads69
 72
 (4.2)% (14.2)% 136
 140
 (2.9)% (3.1)%
Total electric deliveries6,882
 6,751
 1.9 % (1.1)% 14,670
 13,962
 5.1 % 0.5 %
 As of June 30,
Number of Electric Customers2018 2017
Residential1,163,789
 1,154,330
Small commercial & industrial113,745
 113,329
Large commercial & industrial12,183
 12,113
Public authorities & electric railroads268
 276
Total1,289,985
 1,280,048
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

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BGE Natural Gas Operating Statistics and Detail
Deliveries to Customers (in mmcf)Three Months Ended
June 30,		 % Change Weather -
Normal
% Change		 Six Months Ended
June 30,		 % Change Weather -
Normal
% Change
2018 2017  2018 2017 
Retail Deliveries(a)
               
Residential5,271
 3,613
 45.9% 15.1% 27,046
 21,730
 24.5% 4.0%
Small commercial & industrial1,433
 1,075
 33.3% 13.3% 6,207
 4,853
 27.9% 8.2%
Large commercial & industrial10,167
 8,340
 21.9% 18.2% 25,817
 22,816
 13.2% 7.2%
Other(b)
2,661
 116
 2,194.0% n/a
 8,039
 2,395
 235.7% n/a
Total natural gas deliveries19,532
 13,144
 48.6% 16.9% 67,109
 51,794
 29.6% 5.8%
 As of June 30,
Number of Gas Customers2018
2017
Residential630,714
 624,392
Small commercial & industrial38,274
 38,211
Large commercial & industrial5,900
 5,809
Total674,888

668,412
_________
(a)Reflects delivery volumes from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Other natural gas revenue includes off-system sales of 2,661 mmcfs and 116 mmcfs for the three months ended June 30, 2018 and 2017, respectively. Other natural gas revenue includes off-system sales of 8,039 mmcfs and 2,395 mmcfs for the six months ended June 30, 2018 and 2017. respectively.
See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

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Results of Operations — PHI
PHI’s results of operations include the results of its three reportable segments, Pepco, DPL and ACE for all periods presented below. All material intercompany accounts and transactions have been eliminated in consolidation. A separate specific discussion of the results of operations for Pepco, DPL and ACE is presented elsewhere in this report.
 Three Months Ended
June 30,		 Favorable (Unfavorable) Variance Six Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 2018 2017  2018 2017 
Operating revenues$1,076
 $1,074
 $2
 $2,327
 $2,248
 $79
Purchased power and fuel expense381
 383
 2
 901
 845
 (56)
Revenues net of purchased power and fuel expense(a)
695
 691
 4
 1,426
 1,403
 23
Other operating expenses           
Operating and maintenance255
 269
 14
 563
 524
 (39)
Depreciation and amortization180
 165
 (15) 363
 332
 (31)
Taxes other than income107
 110
 3
 221
 221
 —
Total other operating expenses542
 544
 2
 1,147
 1,077
 (70)
Gain on sales of assets—
 1
 (1) —
 1
 (1)
Operating income153
 148
 5
 279
 327
 (48)
Other income and (deductions)           
Interest expense, net(65) (59) (6) (128) (122) (6)
Other, net11
 13
 (2) 22
 26
 (4)
Total other income and (deductions)(54) (46) (8) (106) (96) (10)
Income before income taxes99
 102
 (3) 173
 231
 (58)
Income taxes15
 36
 21
 24
 26
 2
Net income$84
 $66
 $18
 $149
 $205
 $(56)
_________
(a)PHI evaluates its operating performance using the measure of revenue net of purchased power and fuel expense for electric and natural gas sales. PHI believes revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. PHI has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017.PHI's Net income for the three months ended June 30, 2018 was $84 million compared to $66 million for the three months ended June 30, 2017.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $4 million for the three months ended June 30, 2018 compared to the same period in 2017 primarily due to higher utility revenues due to regulatory rate increases at Pepco, DPL and ACE, partially offset by lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates and lower affiliate revenues at PHISCO as a result of the completion of integration transition activities.

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Operating and maintenance expense decreased by $14 million for the three months ended June 30, 2018 compared to the same period in 2017. The decrease is attributable to the following factors:
Decrease of $22 million across all companies primarily related to lower uncollectible accounts expense as a result of lower accounts receivable;
Net decrease of $1 million in labor and contracting expense which is made up of a decrease of $13 million at PHISCO as a result of the completion of integration transition activities, partially offset by an increase of $12 million at Pepco, DPL and ACE.
Depreciation and amortization expense for the three months ended June 30, 2018 compared to the same period in 2017 increased by $15 million due to ongoing capital expenditures as well as higher amortization of regulatory assets as a result of ratemaking activity.
Taxes other than income for the three months ended June 30, 2018 compared to the same period in 2017 remained relatively consistent.
Gain on sales of assets during the three months ended June 30, 2018 compared to the same period in 2017 decreased $1 million due to the sale of land in June 2017.
Interest expense, net for the three months ended June 30, 2018 compared to the same period in 2017 increased by $6 million due to higher outstanding debt.
Other, net for the three months ended June 30, 2018 compared to the same period in 2017 remained relatively consistent.
PHI's effective income tax rate was 15.2% and 35.3% for the three months ended June 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three months ended June 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017.PHI's Net income for the three months ended June 30, 2018 was $149 million compared to $205 million for the three months ended June 30, 2017.
Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $23 million for the six months ended June 30, 2018 compared to the same period in 2017 primarily due to higher utility revenues due to regulatory rate increases at Pepco, DPL and ACE, partially offset by lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates and lower affiliate revenues at PHISCO as a result of the completion of integration transition activities.
Operating and maintenance expense increased by $39 million for the six months ended June 30, 2018 compared to the same period in 2017. The increase is attributable to the following factors:
Net increase of $11 million in labor and contracting expense which is made up of an increase of $27 million at Pepco, DPL and ACE, partially offset by a decrease of $16 million at PHISCO as a result of the completion of integration transition activities;
Increase of $8 million at DPL due to deferral of integration costs in 2017;
Increase of $4 million across all companies primarily related to higher uncollectible accounts expense as a result of higher accounts receivable.


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Depreciation and amortization expense for the six months ended June 30, 2018 compared to the same period in 2017 increased by $31 million due to ongoing capital expenditures as well as higher amortization of regulatory assets as a result of ratemaking activity.
Taxes other than income for the six months ended June 30, 2018 compared to the same period in 2017 remained relatively consistent.
Gain on sales of assets during the six months ended June 30, 2018 compared to the same period in 2017 decreased $1 million due to the sale of land in June 2017.
Interest expense, net for the six months ended June 30, 2018 compared to the same period in 2017 increased $6 million due to higher outstanding debt.
Other, net for the six months ended June 30, 2018 compared to the same period in 2017 remained relatively consistent.
PHI's effective income tax rate was 13.9% and 11.3% for the six months ended June 30, 2018 and 2017, respectively. The increase in the effective income tax rate for the six months ended June 30, 2018 compared to the same periods in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA, partially offset by a nonrecurring adjustment to income tax reserve balances in 2017. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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Results of Operations - Pepco
 Three Months Ended June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) Variance
2018 2017  2018 2017 
Operating revenues$523
 $514
 $9
 $1,080
 $1,045
 $35
Purchased power expense140
 143
 3
 322
 309
 (13)
Revenues net of purchased power expense(a)
383
 371
 12
 758
 736
 22
Other operating expenses           
Operating and maintenance116
 120
 4
 246
 234
 (12)
Depreciation and amortization92
 78
 (14) 188
 160
 (28)
Taxes other than income90
 90
 —
 183
 180
 (3)
Total other operating expenses298
 288
 (10) 617
 574
 (43)
Gain on sales of assets—
 1
 (1) —
 1
 (1)
Operating income85
 84
 1
 141
 163
 (22)
Other income and (deductions)    
     
Interest expense, net(32) (28) (4) (63) (58) (5)
Other, net8
 7
 1
 16
 15
 1
Total other income and (deductions)(24) (21) (3) (47) (43) (4)
Income before income taxes61
 63
 (2) 94
 120
 (26)
Income taxes7
 20
 13
 9
 19
 10
Net income$54
 $43
 $11
 $85
 $101
 $(16)
_________
(a)Pepco evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. Pepco believes revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Pepco has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
Net Income
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017.Pepco's Net income for the three months ended June 30, 2018, was higher than the same period in 2017, primarily due to higher electric distribution base rates charged to customers in Maryland that became effective in October 2017 and June 2018 and higher electric distribution base rates charged to customers in the District of Columbia that became effective August 2017 and lower uncollectible accounts expense as a result of lower accounts receivable, partially offset by higher Operating and maintenance expense attributable to an increase in labor and contracting expense and higher Depreciation and amortization expense attributable to ongoing capital expenditures. The TCJA did not significantly impact Pepco's Net income for the three months ended June 30, 2018 as the favorable tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017.Pepco's Net income for the six months ended June 30, 2018, was lower than the same period in 2017 primarily due to higher Depreciation and amortization expense attributable to ongoing capital expenditures, higher

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Operating and maintenance expense attributable to an increase in labor and contracting expense and higher uncollectible accounts expense as a result of higher accounts receivable, partially offset by higher electric distribution base rates charged to customers in Maryland that became effective in October 2017 and June 2018 and higher electric distribution base rates charged to customers in the District of Columbia that became effective August 2017. The TCJA did not significantly impact Pepco's Net income for the six months ended June 30, 2018 as the favorable tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Revenues Net of Purchased Power Expense
Operating revenues include revenue from the distribution and supply of electricity to Pepco’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology. Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All Pepco customers have the choice to purchase electricity from competitive electric generation suppliers. The customers' choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and six months ended June 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2018 2017 2018 2017
Electric67% 67% 64% 66%
Retail customers purchasing electric generation from competitive electric generation suppliers at June 30, 2018 and 2017 consisted of the following:
 June 30, 2018 June 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric177,786
 20% 179,736
 21%
Retail deliveries purchased from competitive electric generation suppliers represented 74% and 72% of Pepco’s retail kWh sales to the District of Columbia customers and 61% and 58% of Pepco’s retail kWh sales to Maryland customers for the three and six months ended June 30, 2018, respectively and 74% and 74% of Pepco’s retail kWh sales to the District of Columbia customers and 61% and 60% of Pepco’s retail kWh sales to Maryland customers for the three and six months ended June 30, 2017, respectively.

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The changes in Pepco’s operating revenues net of purchased power expense for the three and six months ended June 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended June 30, 2018 Six Months Ended June 30, 2018
 Increase (Decrease) Increase (Decrease)
Volume$3
 $6
Distribution revenue4
 3
Regulatory required programs5
 19
Transmission revenues(3) (7)
Other3
 1
Total increase$12
 $22
Revenue Decoupling. Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the District of Columbia, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland and the District of Columbia to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 20-year period in Pepco's service territory. The changes in heating and cooling degree-days in Pepco’s service territory for the three and six months ended June 30, 2018 compared to the same periods in 2017 and normal weather consisted of the following:
Heating and Cooling Degree-Days    % Change
Three Months Ended June 30,2018 2017 Normal 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days327
 207
 307
 58.0% 6.5%
Cooling Degree-Days575
 546
 486
 5.3% 18.3%
       

 

Six Months Ended June 30,      

 

Heating Degree-Days2,456
 1,955
 2,436
 25.6% 0.8%
Cooling Degree-Days578
 550
 489
 5.1% 18.2%
Volume. The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and six months ended June 30, 2018 compared to the same periods in 2017, primarily reflects the impact of residential customer growth.
Distribution Revenue.   The increase in distribution revenues for the three and six months ended June 30, 2018 compared to the same periods in 2017 was primarily due to higher electric distribution base rates charged to customers in Maryland that became effective in October 2017 and June 2018 and higher electric distribution base rates charged to customers in the District of Columbia that became effective August 2017, partially offset by the impact of reduced distribution rates to reflect the lower

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federal income tax rate. See Note 6—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs.This represents the change in Operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in Pepco's Consolidated Statements of Operations and Comprehensive Income. See Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs. Revenue from regulatory required programs increased for the three and six months ended June 30, 2018 compared to the same periods in 2017 due to increases in the Maryland and District of Columbia surcharge rates and sales due to higher volumes, as well as the DC PLUG surcharge which became effective in February 2018.
Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, the highest daily peak load and other billing adjustments. The decrease in transmission revenues for the three and six months ended June 30, 2018 compared to the same periods in 2017 is a result of a decrease in network transmission service peak loads.
Other.Other revenue, which can vary period to period, includes rental revenue, revenue related to late payment charges, assistance provided to other utilities through mutual assistance programs, and recoveries of other taxes.
Operating and Maintenance Expense
 Three Months Ended
June 30,		 Increase (Decrease) Six Months Ended
June 30,		 
Increase
(Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense - baseline$113
 $114
 $(1) $239
 $228
 $11
Operating and maintenance expense - regulatory required programs(a)
3
 6
 (3) 7
 6
 1
Total operating and maintenance expense$116
 $120
 $(4) $246
 $234
 $12
_________
(a)Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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The changes in Operating and maintenance expense for the three and six months ended June 30, 2018 compared to the same periods in 2017, consisted of the following:
 Three Months Ended June 30, 2018 Six Months Ended June 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Uncollectible accounts expense(8) 3
Labor and contracting(a)
5
 6
Other2
 2
 (1) 11
    
Regulatory required programs(3) 1
Total (decrease) increase$(4) $12
_________
(a)Includes additional costs associated with mutual assistance programs. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and six months ended June 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended June 30, 2018 Six Months Ended June 30, 2018
 Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$3
 $5
Regulatory asset amortization(b)
5
 14
Regulatory required programs(c)
6
 9
Total increase$14
 $28
_________
(a)Depreciation expense increased due to ongoing capital expenditures.
(b)Regulatory asset amortization increased due to additional regulatory assets related to rate case activity.
(c)Regulatory required programs increased as a result of higher amortization of the DC PLUG regulatory asset. Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.
Taxes Other Than Income
Taxes other than income for the three months ended June 30, 2018 compared to the same period in 2017 remained relatively consistent.
Taxes other than income for the six months ended June 30, 2018 compared to the same period in 2017, increased due to an increase in the utility taxes that are collected and passed through by Pepco (which is substantially offset in Operating revenues).
Gain on Sales of Assets
The decrease in Gain on sales of assets during the three and six months ended June 30, 2018, compared to the same period in 2017, is primarily due to the sale of land in June 2017.

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Interest Expense, Net
Interest expense, net for the three and six months ended June 30, 2018 compared to the same periods in 2017 increased due to higher outstanding debt.
Other, Net
Other, net for the three and six months ended June 30, 2018 compared to the same periods in 2017 remained relatively consistent.
Effective Income Tax Rate
Pepco's effective income tax rate was 11.5% and 31.7% for the three months ended June 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three months ended June 30, 2018 compared to the same periods in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA.
Pepco's effective income tax rate was 9.6% and 15.8% for the six months ended June 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the six months ended June 30, 2018 compared to the same periods in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA, partially offset by a nonrecurring adjustment to income tax reserve balances in 2017.
See Note 1214 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
Pepco Electric Operating Statistics and Detail
166
Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		   Weather - Normal % Change Six Months Ended
June 30,		   Weather - Normal % Change
2018 2017 % Change  2018 2017 % Change 
Retail Deliveries(a)
               
Residential1,799
 1,757
 2.4 % (5.6)% 4,082
 3,757
 8.7 % (0.6)%
Small commercial & industrial309
 326
 (5.2)% (7.9)% 655
 652
 0.5 % (3.0)%
Large commercial & industrial3,693

3,675
 0.5 % (1.6)% 7,363
 7,160
 2.8 % 0.8 %
Public authorities & electric railroads174
 172
 1.2 % 1.2 % 350
 362
 (3.3)% (3.6)%
Total retail deliveries5,975
 5,930
 0.8 % (3.1)% 12,450
 11,931
 4.4 % — %
 As of June 30,
Number of Electric Customers2018 2017
Residential798,741
 787,708
Small commercial & industrial53,460
 53,393
Large commercial & industrial21,846
 21,767
Public authorities & electric railroads147
 139
Total874,194
 863,007
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

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DPL

See Note 19 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

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Results of Operations -— DPL
 Three Months Ended June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) Variance
2018 2017  2018 2017 
Operating revenues$289
 $282
 $7
 $673
 $644
 $29
Purchased power and fuel expense114
 113
 (1) 291
 270
 (21)
Revenues net of purchased power and fuel expense(a)
175
 169
 6
 382
 374
 8
Other operating expenses

 

   

 

  
Operating and maintenance77
 74
 (3) 175
 148
 (27)
Depreciation and amortization43
 40
 (3) 88
 79
 (9)
Taxes other than income13
 14
 1
 28
 28
 —
Total other operating expenses133
 128
 (5) 291
 255
 (36)
Operating income42
 41
 1
 91
 119
 (28)
Other income and (deductions)

 

 

 

 

 

Interest expense, net(14) (13) (1) (27) (25) (2)
Other, net3
 3
 —
 5
 6
 (1)
Total other income and (deductions)(11) (10) (1) (22) (19) (3)
Income before income taxes31

31
 —
 69

100
 (31)
Income taxes5
 12
 7
 12
 24
 12
Net income$26
 $19
 $7
 $57
 $76
 $(19)
_________
(a)DPL evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales and revenue net of fuel expense for natural gas sales. DPL believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements because they provide information that can be used to evaluate its operational performance. DPL has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense and Revenue net of fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
Net Income
 Three Months Ended March 31, Favorable (Unfavorable) Variance
2019 2018 
Operating revenues$380
 $384
 $(4)
Purchased power and fuel expense164
 177
 13
Revenues net of purchased power and fuel expense216
 207
 9
Other operating expenses

 

  
Operating and maintenance84
 98
 14
Depreciation and amortization46
 45
 (1)
Taxes other than income14
 15
 1
Total other operating expenses144
 158
 14
Operating income72
 49
 23
Other income and (deductions)

 

 

Interest expense, net(15) (13) (2)
Other, net3
 2
 1
Total other income and (deductions)(12) (11) (1)
Income before income taxes60

38
 22
Income taxes7
 7
 —
Net income$53
 $31
 $22
Three Months Ended June 30, 2018March 31, 2019 Compared to Three Months Ended June 30, 2017.March 31, 2018. Net income DPL's Net income for the three months ended June 30, 2018, was higher than the same period in 2017increased by $22 million primarily due to higher Revenues net of purchased power and fuel expense attributable to higher electric interim distribution base rates charged to customers in Maryland and Delaware that were put into effect throughout 2018, higher transmission base rates and an increase in March 2018 andthe highest daily peak load, the absence of a decreasewrite-off of construction work in progress, lower uncollectible accounts expense, as a result ofand lower accounts receivable, partially offset by higher labor and contracting expense and higher regulatory asset amortization due to additional regulatory assets related to rate case activity. The TCJA did not significantly impact DPL's Net income for the three months ended June 30, 2018 as the favorable tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.storm costs.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017. DPL's Net income for the six months ended June 30, 2018, was lower than the same period in 2017 primarily due to higher Operating and maintenance expense attributable to higher labor and contracting expense, a deferral of integration costs in 2017 and higher regulatory asset amortization due to additional regulatory assets related to rate case activity, partially offset by higher electric interim distribution base rates charged to customers in Delaware that were put into effect in March 2018. The TCJA did not significantly impact

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DPL's Net income for the six months ended June 30, 2018 as the favorable tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Revenues Net of Purchased Power and Fuel Expense
Expense. There are certain drivers to Operating revenues include revenue from the distribution and supply of electricity and natural gas to DPL’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology. Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Natural gas operating revenue includes sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated gas revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other gas revenue consists of off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gasfully offset by regulated customers creates excess pipeline capacity.
Electric and natural gas revenues and purchasedtheir impact on Purchased power and fuel expense, are also affected bysuch 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 participation in the Customer Choice Program. All DPL customersthese costs have minimal impact on RNF.
Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers'suppliers. Customer choice of suppliers doesprograms do not impact the volume of deliveries or RNF, but affects revenue collected from customersimpact Operating revenues related to supplied energy and natural gas service.electricity.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and six months ended June 30, 2018 and 2017,The changes in RNF consisted of the following:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2018 2017 2018 2017
Electric54% 55% 50% 52%
Natural Gas41% 44% 29% 31%
 Three Months Ended
March 31, 2019
 Increase (Decrease)
 Electric Gas Total
Volume$—
 $1
 $1
Distribution4
 (2) 2
Regulatory required programs(2) —
 (2)
Transmission8
 —
 8
Total increase (decrease)$10
 $(1) $9
Retail customers purchasingRevenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric generation and natural gas from competitive electric generation and natural gas suppliers at June 30, 2018 and 2017 consisted of the following:distribution in Maryland are not impacted by abnormal weather or usage per customer as a

167
 June 30, 2018 June 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric73,908
 14.1% 79,620
 15.3%
Natural Gas154
 0.1% 155
 0.1%
Retail deliveries purchased from competitive electric generation suppliers represented 56% and 52% of DPL’s retail kWh sales to Delaware customers and 49% and 45% of DPL's retail kWh sales to Maryland customers for the three and six months ended June 30, 2018, respectively and 57% and 55% of DPL's retail kWh sales to Delaware customers and 51% and 48% of DPL's retail kWh sales to Maryland customers for the three and six months ended June 30, 2017, respectively.

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DPL


The changes in DPL’s Operating revenues netresult of purchased power and fuel expense for the three and six months ended June 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018
 Increase (Decrease) Increase (Decrease)
 Electric Gas Total Electric Gas Total
Weather$2
 $(3) $(1) $6
 $4
 $10
Volume2
 3
 5
 4
 1
 5
Distribution revenue(2) 3
 1
 (10) (2) (12)
Regulatory required programs(1) —
 (1) (1) —
 (1)
Transmission revenues1
 —
 1
 2
 —
 2
Other1
 —
 1
 4
 —
 4
Total increase$3
 $3
 $6
 $5
 $3
 $8
Revenue Decoupling. DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling thecustomer by customer class. While Operating revenues from electric distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers and changes in the approved distribution charge per customer. A modified fixed variable rate design, which would provide for a charge not tied to a customer’s volumetric consumption of electricity or natural gas, has been proposed for DPL electricity and natural gas customers in Delaware. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.customers.
Weather.The demand for electricity and natural gas in areas not subject to the BSADelaware 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"favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. DuringThere was no change in RNF related to weather for the three months ended June 30, 2018March 31, 2019 compared to the same period in 2017, Operating revenue net of purchased power and fuel expense related to weather remained relatively consistent. During the six months ended June 30, 2018 compared to the same period in 2017, Operating revenue net of purchased power and fuel expense related to weather was higher due to the impact of favorable weather conditions in DPL's Delaware service territory..

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Heating and cooling degree-daysdegree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-daysdegree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changesThere were no cooling degree days in heating and cooling degree-days in DPL’sDPL's Delaware electric service territory for the three and six months ended June 30,March 31, 2019 or during the same period in 2018. The changes in heating degree days in DPL’s Delaware service territory for the three months ended March 31, 2019 compared to same period in 2018 and normal weather consisted of the following:
Delaware Electric Service Territory    % Change
Three Months Ended March 31,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days2,522
 2,504
 2,508
 0.7% 0.6%
Delaware Natural Gas Service Territory    % Change
Three Months Ended March 31,2019 2018 Normal 2019 vs. 2018 2019 vs. Normal
Heating Degree-Days2,522
 2,504
 2,496
 0.7% 1.0%
Volume, exclusive of the effects of weather, remained relatively consistent for the three months ended March 31, 2019 compared to the same period in 2017 and normal weather consisted of the following:2018.
Electric Service Territory    % Change
Three Months Ended June 30,2018 2017 Normal 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days460
 358
 468
 28.5% (1.7)%
Cooling Degree-Days372
 361
 334
 3.0% 11.4 %
          
Six Months Ended June 30,         
Heating Degree-Days2,875
 2,452
 2,875
 17.3% — %
Cooling Degree-Days373
 361
 336
 3.3% 11.0 %
Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended
March 31,		 % Change 
Weather - Normal
% Change(b)
2019 2018  
Residential851
 869
 (2.1)% (1.5)%
Small commercial & industrial321
 330
 (2.7)% (2.6)%
Large commercial & industrial810
 829
 (2.3)% (2.2)%
Public authorities & electric railroads8
 9
 (11.1)% (7.3)%
Total electric retail deliveries(a)
1,990
 2,037
 (2.3)% (2.0)%
Natural Gas Service Territory    % Change
Three Months Ended June 30,2018 2017 Normal 2018 vs. 2017 2018 vs. Normal
Heating Degree-Days481
 372
 498
 29.3% (3.4)%
          
Six Months Ended June 30,         
Heating Degree-Days2,985
 2,543
 3,000
 17.4% (0.5)%
Volume. The increase in Operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and six months ended June 30, 2018 compared to the same period in 2017, primarily reflects the impact of increased average residential and commercial customer usage and growth.
Distribution Revenue.  The decrease in electric distribution revenue for the three months ended June 30, 2018, and electric and gas distribution revenue for the six months ended June 30, 2018 compared to the same periods in 2017 was primarily due to reduced electric and gas interim distribution rates in Delaware that were put into effect in March 2018 which reflect the impact of the lower federal income tax rate.  The increase in gas distribution revenue for the three months ended June 30, 2018 compared to the same period in 2017 is primarily due to customer sales mix, partially offset by reduced gas interim distribution rates in Delaware that were put into effect in March 2018. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs.This represents the change in Operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in DPL's Consolidated Statements of Operations and Comprehensive Income. See Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.
Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, the highest daily peak load and other billing adjustments. The transmission revenues for the three and six months ended June 30, 2018 compared to the same period in 2017 remained relatively consistent.

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Other.Other revenue, which can vary period to period, includes rental revenue, revenue related to late payment charges, assistance provided to other utilities through mutual assistance programs, and recoveries of other taxes.
Operating and Maintenance Expense
 Three Months Ended
June 30,		 Increase (Decrease) Six Months Ended
June 30,		 Increase (Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense - baseline$75
 $70
 $5
 $167
 $142
 $25
Operating and maintenance expense - regulatory required programs(a)
2
 4
 (2) 8
 6
 2
Total operating and maintenance expense$77
 $74
 $3
 $175
 $148
 $27
_________
(a)Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
The changes in Operating and maintenance expense for the three and six months ended June 30, 2018 compared to the same period in 2017, consisted of the following:
 Three Months Ended June 30, 2018 Six Months Ended June 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor and contracting(a)
$6
 $10
Uncollectible accounts expense(6) 2
Merger commitments(b)
—
 8
Other5
 5
 5
 25
    
Regulatory required programs(2) 2
Total increase$3
 $27
_________
(a)Includes additional costs associated with mutual assistance programs. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
(b)Reflects deferral of integration costs in 2017.

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Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and six months ended June 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended June 30, 2018 Six Months Ended June 30, 2018
 Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$1
 $3
Regulatory asset amortization(b)
3
 7
Regulatory required programs(c)


(1) (1)
Total increase$3
 $9
_________
(a)Depreciation expense increased due to ongoing capital expenditures.
(b)Regulatory asset amortization increased due to additional regulatory assets related to rate case activity.
(c)Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.
Taxes Other Than Income
Taxes other than income for the three and six months ended June 30, 2018 compared to the same period in 2017 remained relatively consistent.
Interest Expense, Net
Interest expense, net for the three and six months ended June 30, 2018 compared to the same period in 2017 remained relatively consistent.
Other, Net
Other, net for the three and six months ended June 30, 2018 compared to the same period in 2017 remained relatively consistent.
Effective Income Tax Rate
DPL's effective income tax rate was 16.1% and 38.7% for the three months ended June 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three months ended June 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA.
DPL's effective income tax rate was 17.4% and 24.0% for the six months ended June 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the six months ended June 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA, partially offset by a nonrecurring adjustment to income tax reserve balances in 2017.
See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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DPL Electric Operating Statistics and Detail
Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		 % Change Weather - Normal % Change Six Months Ended
June 30,		 % Change Weather - Normal % Change
2018 2017   2018 2017  
Retail Deliveries(a)
               
Residential1,115
 1,045
 6.7 % 2.1 % 2,666
 2,404
 10.9 % 2.9 %
Small commercial & industrial536
 526
 1.9 % 0.8 % 1,105
 1,057
 4.5 % 2.3 %
Large commercial & industrial1,187
 1,131
 5.0 % 4.0 % 2,266
 2,195
 3.2 % 1.9 %
Public authorities & electric railroads10
 12
 (16.7)% (16.7)% 22
 25
 (12.0)% (12.0)%
Total retail deliveries2,848
 2,714
 4.9 % 2.6 % 6,059
 5,681
 6.7 % 2.4 %
As of June 30,As of March 31,
Number of Electric Customers2018 2017
Number of Total Electric Customers (Maryland and Delaware)2019 2018
Residential461,596
 458,361
464,638
 460,863
Small commercial & industrial61,189
 60,499
61,391
 60,962
Large commercial & industrial1,362
 1,410
1,400
 1,383
Public authorities & electric railroads624
 636
620
 625
Total524,771
 520,906
528,049
 523,833
_________
(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.
DPL Natural Gas Operating Statistics and Detail
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Retail Deliveries to Customers (in mmcf)Three Months Ended
June 30,		 % Change Weather - Normal % Change Six Months Ended
June 30,		 % Change Weather - Normal % Change
2018 2017   2018 2017  
Retail Deliveries(a)
               
Residential957
 713
 34.2% 5.6% 5,442
 4,453
 22.2% 4.0 %
Small commercial & industrial644
 513
 25.5% 5.8% 2,521
 2,197
 14.7% (2.4)%
Large commercial & industrial466
 453
 2.9% 2.9% 984
 960
 2.5% 2.5 %
Transportation1,420
 1,324
 7.3% 4.9% 3,633
 3,493
 4.0% 0.6 %
Total natural gas deliveries3,487
 3,003
 16.1% 5.0% 12,580
 11,103
 13.3% 1.5 %

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DPL


As of June 30,
Number of Gas Customers2018 2017
Natural Gas Retail Deliveries to Delaware Customers (in mmcf)Three Months Ended
March 31,		 % Change 
Weather - Normal
% Change(b)
2019 2018 
Residential122,754
 121,166
4,607
 4,485
 2.7% 1.8 %
Small commercial & industrial9,810
 9,725
2,020
 1,878
 7.6% 6.6 %
Large commercial & industrial18
 18
523
 516
 1.4% 1.4 %
Transportation154
 155
2,218
 2,213
 0.2% (0.2)%
Total132,736
 131,064
Total natural gas deliveries(a)
9,368
 9,092
 3.0% 2.3 %
 As of March 31,
Number of Delaware Gas Customers2019 2018
Residential124,575
 123,062
Small commercial & industrial10,023
 9,873
Large commercial & industrial18
 17
Transportation157
 155
Total134,773
 133,107
__________
(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.
Distribution Revenue increased for the three months ended March 31, 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 in Maryland and Delaware that were put into effect throughout 2018. 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 months ended March 31, 2019 compared to the same period in 2018 primarily due to higher rates effective June 2018 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 19 —18 - Segment Information offor the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

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DPL


ResultsThe changes in Operating and maintenance expense consisted of Operations - ACEthe following:
 Three Months Ended June 30, Favorable (Unfavorable) Variance Six Months Ended June 30, Favorable (Unfavorable) Variance
 2018 2017  2018 2017 
Operating revenues$265
 $270
 $(5) $575
 $544
 $31
Purchased power expense128
 128
 —
 289
 266
 (23)
Revenues net of purchased power expense(a)
137
 142
 (5) 286
 278
 8
Other operating expenses    
     
Operating and maintenance75
 78
 3
 165
 152
 (13)
Depreciation and amortization36
 37
 1
 69
 72
 3
Taxes other than income1
 2
 1
 3
 4
 1
Total other operating expenses112
 117
 5
 237
 228
 (9)
Operating income25
 25
 —
 49
 50
 (1)
Other income and (deductions)    
     
Interest expense, net(16) (15) (1) (32) (30) (2)
Other, net1
 2
 (1) 1
 4
 (3)
Total other income and (deductions)(15)
(13) (2) (31)
(26) (5)
Income before income taxes10

12
 (2) 18

24
 (6)
Income taxes2
 4
 2
 3
 (12) (15)
Net income$8
 $8
 $—
 $15
 $36
 $(21)
 Three Months Ended March 31, 2019
 Increase (Decrease)
Baseline 
Labor, other benefits, contracting and materials$3
Uncollectible accounts expense(5)
Storm-related costs(5)
BSC and PHISCO costs(2)
Write-off of construction work in progress(7)
Other(1)
 (17)
  
Regulatory required programs3
Total decrease$(14)
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
_________
(a)ACE evaluates its operating performance using the measure of revenue net of purchased power expenseDepreciation and amortization increased primarily due to ongoing capital expenditures.
(b)Depreciation and amortization expenses for electric sales. ACE believes Revenue net of purchased power expense isregulatory required programs are recoverable from customers on a useful measurement of its performance because it provides information that can be used to evaluate its operational performance. ACEfull and current basis through approved regulated rates. An equal and offsetting amount has included the analysis below as a complement to the financial information providedbeen reflected in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.Operating revenues.
Net Income
Three Months Ended June 30, 2018 Compared to Three Months Ended June 30, 2017.Effective income tax ratesACE's Net income for the three months ended June 30,March 31, 2019 and 2018 remained unchanged from the same period in 2017,were 11.7% and 18.4%, respectively. The decrease is primarily due to higher electric distribution base rates charged to customers in New Jersey that became effective in October 2017 and lower uncollectible accounts expensethe accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as athe result of lower accounts receivable, primarily offset by higher Operating and maintenance expense attributableregulatory settlements.
See Note 12 — Income Taxes of the Combined Notes to higher labor and contracting expense and higher Depreciation and amortization expense attributable to ongoing capital expenditures. The TCJA did not significantly impact ACE’s Net incomeConsolidated Financial Statements for additional information regarding the three months ended June 30, 2018 ascomponents of the favorablechange in effective income tax impacts were predominately offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Six Months Ended June 30, 2018 Compared to Six Months Ended June 30, 2017.ACE's Net income for the six months ended June 30, 2018, was lower than the same period in 2017, primarily due to higher Operating and maintenance expense attributable to higher labor and contracting expense and higher Depreciation and amortization expense attributable to ongoing capital expenditures, partially offset by higher electric distribution base rates charged to customers in New Jersey that became effective in October 2017. The TCJA did not significantly impact ACE’s Net income for the six months ended June
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ACE


30,Results of Operations — ACE
 Three Months Ended March 31, Favorable (Unfavorable) Variance
 2019 2018 
Operating revenues$273
 $310
 $(37)
Purchased power expense139
 161
 22
Revenues net of purchased power expense134
 149
 (15)
Other operating expenses    
Operating and maintenance81
 90
 9
Depreciation and amortization31
 33
 2
Taxes other than income1
 3
 2
Total other operating expenses113
 126
 13
Operating income21
 23
 (2)
Other income and (deductions)    
Interest expense, net(14) (16) 2
Other, net3
 1
 2
Total other income and (deductions)(11)
(15) 4
Income before income taxes10

8
 2
Income taxes—
 1
 1
Net income$10
 $7
 $3
Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018.Net income increased by $3 million primarily due to increased transmission base rates that became effective June 2018 asand an increase in the favorable income tax impacts were predominatelyhighest daily peak loads, partially offset by lower revenues resulting from the pass back of the tax savings through customer rates. average residential usage.
Revenues Net of Purchased Power Expense
and Fuel Expense. There are certain drivers to Operating revenues include revenuethat 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 the distribution and supply of electricity to ACE’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology. Operating revenues also include revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, revenue from the resale in the PJM wholesale markets for energy and capacity purchased under contacts with unaffiliated NUGs, and revenue from transmission enhancement credits. Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.
Electric revenues and purchased power expense are also affected bywithout mark-up. Therefore, fluctuations in participation in the Customer Choice Program. All ACE customersthese costs have no impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. The customer'sCustomer choice of supplier doesprograms do not impact the volume of deliveries or RNF, but affects revenue collected from customersimpact Operating revenues related to supplied energy service.electricity.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and six months ended June 30, 2018 compared to the same periodThe changes in 2017RNF consisted of the following:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2018 2017 2018 2017
Electric50% 51% 48% 50%
Retail customers purchasing electric generation from competitive electric generation suppliers at June 30, 2018 and 2017 consisted of the following:
 June 30, 2018 June 30, 2017
 Number of customers % of total retail customers Number of customers % of total retail customers
Electric84,629
 15% 92,895
 17%

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The changes in ACE’s operating revenue net of purchased power expense for the three and six months ended June 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018
 Increase (Decrease) Increase (Decrease)
Weather$2
 $5
Volume(1) 6
Distribution revenue6
 9
Regulatory required programs(13) (14)
Transmission revenues1
 —
Other—
 2
Total (decrease) increase$(5) $8
 Three Months Ended
March 31, 2019
 Increase (Decrease)
Volume$(6)
Distribution(3)
Regulatory required programs(11)
Transmission5
Total decrease$(15)
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. DuringThere was no change in RNF related to weather for the three and six months ended June 30, 2018March 31, 2019 compared to the same period in 2017, operating revenue net2018.

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Table of purchased power and fuel expense related to weather was higher due to the impact of favorable weather conditions in ACE's service territory.Contents
For retail customers of ACE distribution revenues are not decoupled from the distribution of electricity by ACE, and thus are subject to variability due to changes in customer consumption. Therefore, changes in customer usage (due to weather conditions, energy prices, energy savings programs or other reasons) from period to period have a direct impact on reported distribution revenue for customers in ACE's service territory.


Heating and cooling degree-daysdegree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-daysdegree days for a 20-year period in ACE’s service territory. The changes in heating andThere were no cooling degree-daysdegree days in ACE’s service territory for the three and six months ended June 30,March 31, 2019 or during the same period in 2018. The changes in heating degree days in ACE’s service territory for the three months ended March 31, 2019 compared to same period in 2018 consisted of the following:
Heating Degree-Days  Normal % Change
Three Months Ended March 31,2019 2018  2019 vs. 2018 2019 vs. Normal
Heating Degree-Days2,506
 2,413
 2,489
 3.9% 0.7%
Volume,exclusive of the effects of weather, decreased for the three months ended March 31, 2019 compared to the same period in 2017 consisted of the following:2018, primarily due to lower average residential usage.
Heating and Cooling Degree-Days  Normal % Change
Three Months Ended June 30,2018 2017  2018 vs. 2017 2018 vs. Normal
Heating Degree-Days515
 435
 554
 18.4% (7.0)%
Cooling Degree-Days354
 324
 292
 9.3% 21.2 %
       

 

Six Months Ended June 30,      

 

Heating Degree-Days2,927
 2,585
 3,028
 13.2% (3.3)%
Cooling Degree-Days354
 324
 293
 9.3% 20.8 %
Volume.During the three months ended June 30, 2018 compared to the same period in 2017 the operating revenue net of purchased power expense related to delivery volume, exclusive of the effects of weather, was relatively consistent. During the six months ended June 30, 2018 compared to the same period in 2017 the decrease in operating revenue net of purchased power expense related to delivery volume, exclusive of the effects of weather, is primarily due to higher average residential and commercial usage.

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Distribution Revenue.The increase in distribution revenue for the three and six months ended June 30, 2018 compared to the same period in 2017 was primarily due to higher electric distribution base rates charged to customers that became effective in October 2017, partially offset by the impact of reduced distribution rates to reflect the lower federal income tax rate. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs. This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in ACE's Consolidated Statements of Operations and Comprehensive Income. See Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs. Revenue from regulatory required programs decreased for the three and six months ended June 30, 2018 compared to the same periods in 2017 due to a rate decrease effective October 2017 for the ACE Transition Bonds.
Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, the highest daily peak load and other billing adjustments. The transmission revenue net of purchased power expense for the three and six months ended June 30, 2018 compared to the same periods in 2017 remained relatively consistent.
Other.Other revenue, which can vary period to period, includes rental revenue, revenue related to late payment charges, assistance provided to other utilities through mutual assistance programs, and recoveries of other taxes.
Operating and Maintenance Expense
Electric Retail Deliveries to Customers (in GWhs)Three Months Ended
March 31,		 % Change 
Weather - Normal
% Change(b)
2019 2018  
Residential908
 990
 (8.3)% (8.8)%
Small commercial & industrial310
 314
 (1.3)% (1.3)%
Large commercial & industrial791
 824
 (4.0)% (4.1)%
Public authorities & electric railroads13
 15
 (13.3)% (10.6)%
Total electric retail deliveries(a)
2,022
 2,143
 (5.6)% (5.9)%
 Three Months Ended June 30, Increase (Decrease) Six Months Ended June 30, 
Increase
(Decrease)
 2018 2017  2018 2017 
Operating and maintenance expense - baseline$68
 $70
 $(2) $151
 $136
 $15
Operating and maintenance expense - regulatory required programs(a)
7
 8
 (1) 14
 16
 (2)
Total operating and maintenance expense$75
 $78
 $(3) $165
 $152
 $13
_________
(a)Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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The changes in Operating and maintenance expense for the three and six months ended June 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018
 Increase (Decrease) Increase (Decrease)
Baseline   
Labor and contracting(a)
$1
 $11
Uncollectible accounts expense(7) (1)
Other4
 5
 (2) 15
    
Regulatory required programs(1) (2)
Total increase$(3) $13
_________
(a)Includes additional costs associated with mutual assistance programs. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for the three and six months ended June 30, 2018 compared to the same period in 2017 consisted of the following:
 Three Months Ended
June 30, 2018		 Six Months Ended
June 30, 2018
 Increase (Decrease) Increase (Decrease)
Depreciation expense(a)
$1
 $3
Regulatory asset amortization3
 3
Regulatory required programs(b)
(5) (9)
Total decrease$(1) $(3)
_________
(a)Depreciation expense increased due to ongoing capital expenditures.
(b)Regulatory required programs decreased as a result of lower revenue due to rate decreases effective October 2017 for the ACE Transition Bonds. Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.
Taxes Other Than Income
Taxes other than income for the three and six months ended June 30, 2018 compared to the same period in 2017 remained relatively consistent.
Interest Expense, Net
Interest expense, net for the three and six months ended June 30, 2018 compared to the same period in 2017 remained relatively consistent.
Other, Net
Other, net for the three and six months ended June 30, 2018 compared to the same period in 2017 remained relatively consistent.

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Effective Income Tax Rate
ACE's effective income tax rate was 20.0% and 33.3% for the three months ended June 30, 2018 and 2017, respectively. The decrease in the effective income tax rate for the three months ended June 30, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA.
ACE's effective income tax rate was 16.7% and (50.0)% for the six months ended June 30, 2018 and 2017, respectively. The increase in the effective income tax rate for the six months ended June 30, 2018 compared to the same period in 2017 is primarily due to the absence of an unrecognized tax benefit from 2017, partially offset by a nonrecurring adjustment to income tax reserve balances in 2017.
See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
ACE Electric Operating Statistics and Detail
Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		 % Change Weather - Normal % Change Six Months Ended
June 30,		 % Change Weather - Normal % Change
2018 2017   2018 2017  
Retail Deliveries(a)
               
Residential825
 814
 1.4% (2.2)% 1,815
 1,693
 7.2% 2.9%
Small commercial & industrial309
 302
 2.3% 0.3 % 623
 585
 6.5% 4.6%
Large commercial & industrial872
 853
 2.2% 1.4 % 1,696
 1,618
 4.8% 4.0%
Public authorities & electric railroads11
 11
 —% — % 26
 24
 8.3% 8.3%
Total retail deliveries2,017
 1,980
 1.9% (0.3)% 4,160
 3,920
 6.1% 3.6%
As of June 30,As of March 31,
Number of Electric Customers2018 20172019 2018
Residential489,050
 486,173
491,935
 488,495
Small commercial & industrial61,134
 61,013
61,377
 61,059
Large commercial & industrial3,590
 3,744
3,494
 3,611
Public authorities & electric railroads654
 629
661
 643
Total554,428
 551,559
557,467
 553,808
_________
(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 decreased for the three months ended March 31, 2019 compared to the same period in 2018 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 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds and BGS administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.
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 months ended March 31, 2019 compared to the same period in 2018 primarily due to a rate increase effective June 2018 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.
See Note 19 —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:

Table
 Three Months Ended
March 31, 2019
 Increase (Decrease)
Baseline 
Labor, other benefits, contracting and materials$(4)
Uncollectible accounts expense(a)
(5)
Storm-related costs(2)
BSC and PHISCO costs(2)
Other(6)
 (19)
  
Regulatory required programs10
Total decrease$(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.
The changes in Depreciation and amortizationexpense consisted of Contentsthe following:
 Three Months Ended
March 31, 2019
 Increase (Decrease)
Depreciation and amortization(a)
$2
Regulatory required programs(b)
(4)
Total decrease$(2)
_________
(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.
Effective income tax rates were 0% and 12.5% for the three months ended March 31, 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 Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to unsecured revolving credit facilities with aggregate bank commitments of $9 billion. In addition, Generation has $545$645 million in bilateral facilities with banks which have various expirations between JanuaryOctober 2019 and December 2019.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 ACE operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information ofon 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 on the NRC minimum funding requirements.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 decommissioning trustNDT fund investment performance going forward. Within two years after shutting down a plant, Generation must submit a post-shutdown decommissioning activities report (PSDAR) to the NRC that includes the planned option for decommissioning the site. As discussed in Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements, Generation filed its annual decommissioning funding status report with the NRC on March 28, 2018 for shutdown reactors and reactors within five years of shut down. As of June 30, 2018,31, 2019, across the alternative decommissioning

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approaches available, Exelon would not be required to post a parental guarantee for TMI or Oyster Creek. InSee Note 13 — Nuclear Decommissioning of the event PSEG decidesCombined Notes to early retire Salem, Generation estimates a parental guarantee of up to $55 million from Exelon could be requiredConsolidated Financial Statements for Salem, dependent upon the ultimate decommissioning approach selected.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 the ultimate amounts 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, across the four alternative decommissioning approaches available, if TMI or Oyster Creek were to fail to obtain the exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $195 million and $210$90 million net of taxes respectively, dependent uponunder SAFSTOR. On April 5, 2019, Generation filed with the ultimate NRC the TMI PSDAR which details the selection of the SAFSTOR option for

decommissioning approach selected. In the event PSEG decidesplant. On October 19, 2018, the NRC granted Generation's exemption request to early retire Salemuse the Oyster Creek NDT funds for non-radiological decommissioning costs.
On July 31, 2018, Generation entered into an agreement for the sale of Oyster Creek which is expected to occur in the second half of 2019. See Note 3 - Mergers, Acquisitions and Salem wereDispositions for additional information on the sale of Oyster Creek to fail to obtain the exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $95 million net of taxes.Holtec.
Cash Flows from Operating Activities
General
Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers.
The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, competitive suppliers, and their ability to achieve operating cost reductions.
See Notes 34 — Regulatory Matters and 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 20172018 Form 10-K for additional information of regulatory and legal proceedings and proposed legislation.

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The following table provides a summary of the major items affecting Exelon’schange in cash flows from operationsprovided by (used in) operating activities for the sixthree months ended June 30,March 31, 2019 and 2018 and 2017:by Registrant:
 Six Months Ended
June 30,		  
 2018 2017 Variance
Net income$1,179
 $1,066
 $113
Add (subtract):     
Non-cash operating activities(a)
3,689
 3,279
 410
Pension and non-pension postretirement benefit contributions(345) (325) (20)
Income taxes129
 58
 71
Changes in working capital and other noncurrent assets and liabilities(b)
(828) (1,002) 174
Option premiums received (paid), net(36) (8) (28)
Collateral (posted) received, net81
 (173) 254
Net cash flows provided by operations$3,869
 $2,895
 $974
_________
(a)Represents depreciation, amortization and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts, pension and other postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets, gain on sale of assets and businesses and other non-cash charges. See Note 18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information on non-cash operating activity.
(b)Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.
Pension and Other Postretirement Benefits
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). Exelon's funding strategy for its qualified pension plans is to contribute the greater of (1) $300 million (inclusive of PHI) and (2) the minimum amounts under ERISA to avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future period required pension contributions. Unlike the qualified pension plans, Exelon's non-qualified pension plans are not funded given that they are not subject to statutory minimum contribution requirements.
While other postretirement plans are plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon's management has historically considered several factors in determining the level of contributions to its other postretirement benefit plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery).
To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.

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On October 3, 2017, the U.S. Department of Treasury and IRS released final regulations updating the mortality tables to be used for defined benefit pension plan funding, as well as the valuation of lump sum and other accelerated distribution options, effective for plan years beginning in 2018. The new mortality tables reflect improved projected life expectancy as compared to the existing table, which is generally expected to increase minimum pension funding requirements, Pension Benefit Guaranty Corporation premiums and the value of lump sum distributions. The IRS permits plan sponsors the option of delaying use of the new mortality tables for determining minimum funding requirements until 2019, which Exelon has utilized. The one-year delay does not apply for use of the mortality tables to determine the present value of lump sum distributions.
Tax Matters
The Registrants’ future cash flows from operating activities may be affected by the following tax matters:
Pursuant to the TCJA, beginning in 2018 Generation is expected to have higher operating cash flows in the range of approximately $1.2 billion to $1.6 billion for the period from 2018 to 2021, reflecting the reduction in the corporate federal income tax rate and full expensing of capital investments.
The TCJA is generally expected to result in lower operating cash flows for the Utility Registrants as a result of the elimination of bonus depreciation and lower customer rates. Increased operating cash flows for the Utility Registrants from lower corporate federal income tax rates is expected to be more than offset over time by lower customer rates resulting from lower income tax expense recoveries and the settlement of deferred income tax net regulatory liabilities established pursuant to the TCJA, partially offset by the impacts of higher rate base. The amount and timing of settlement of the net regulatory liabilities will be determined by the Utility Registrants’ respective rate regulators, subject to certain IRS “normalization” rules. The table below sets forth the Registrants’ estimated categorization of their net regulatory liabilities as of December 31, 2017. The amounts in the table below are shown on an after-tax basis reflecting future net cash outflows after taking into consideration the income tax benefits associated with the ultimate settlement with customers.
 Exelon ComEd 
PECO(a)
 BGE PHI PEPCO DPL ACE
Subject to IRS Normalization Rules$3,040 $1,400 $533 $459 $648 $299 $195 $153
Subject to Rate Regulator Determination1,694 573 43 324 754 391 194 170
Net Regulatory Liabilities$4,734 $1,973 $576 $783 $1,402 $690 $389 $323
__________
(a)Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants. See Note 6 - Regulatory Matters for additional information.
Net regulatory liability amounts subject to normalization rules generally may not be passed back to customers any faster than over the remaining useful lives of the underlying assets giving rise to the associated deferred income taxes. Such deferred income taxes generally relate to property, plant and equipment with remaining useful lives ranging from 30 to 40 years across the Utility Registrants. For the remaining amounts, the pass back period is subject to determinations by the rate regulators.
The Utility Registrants expect to fund any such required incremental operating cash outflows using a combination of third party debt financings and equity funding from Exelon in combinations generally consistent with existing capitalization ratio structures. To fund any

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additional equity contributions to the Utility Registrants, Exelon would have available to it its typical sources, including, but not limited to, the increased operating cash flows at Generation referenced above, which over time are expected to exceed the incremental equity needs at the Utility Registrants.
The Utility Registrants continue to work with their state regulatory commissions to determine the amount and timing of the passing back of TCJA income tax savings benefits to customers; with filings made at PECO, Pepco DC and DPL Delaware and approved filings at ComEd, BGE, Pepco Maryland, DPL Maryland and ACE. The amounts being passed back or proposed to be passed back to customers reflect the benefit of lower income tax expense beginning January 1, 2018 (February 1, 2018 for DPL Delaware), and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. See Note 6 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on their filings.
In general, most states use federal taxable income as the starting point for computing state corporate income tax. Now that the TCJA has been enacted, state governments are beginning to analyze the impact of the TCJA on their state revenues. Exelon is uncertain regarding what the state governments will do, and there is a possibility that state corporate income taxes could change due to the enactment of the TCJA. In 2018, Exelon will be closely monitoring the states’ responses to the TCJA as these could have an impact on Exelon’s future cash flows.
See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Information for additional information on the amounts of the net regulatory liabilities subject to determinations by rate regulators.
State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax, property taxes and other taxes or the imposition, extension or permanence of temporary tax increases.
Cash flows from operations for the six months ended June 30, 2018 and 2017 by Registrant were as follows:
 Six Months Ended
June 30,
 2018 2017
Exelon$3,869
 $2,895
Generation2,063
 974
ComEd602
 788
PECO254
 368
BGE464
 469
PHI487
 403
Pepco227
 129
DPL216
 194
ACE67
 77

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Change - Cash Provided by (Used in)Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Net income$330
 $236
 $(8) $55
 $32
 $52
 $24
 $22
 $3
Add (subtract):                 
Non-cash operating activities(494) (575) 17
 10
 15
 (38) (15) (16) (8)
Pension and non-pension postretirement benefit contributions3
 (16) (29) (1) 5
 49
 3
 —
 6
Income taxes55
 67
 10
 15
 (6) 13
 7
 10
 (1)
Changes in working capital and other noncurrent assets and liabilities(498) (145) (23) (21) (113) (126) (64) (33) 1
Option premiums received, net33
 33
 —
 —
 —
 —
 —
 —
 —
Collateral posted, net113
 127
 (10) —
 (1) —
 —
 —
 —
Net cash flows provided by (used in) operations$(458) $(273) $(43) $58
 $(68) $(50) $(45) $(17) $1
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 sixthree months ended June 30,March 31, 2019 and 2018 and 2017 were as follows:
Generation
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. During the six months ended June 30, 2018 and 2017, Generation had net collections/(payments) of counterparty cash collateral of $91 million and $(163) million, respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.
During the six months ended June 30, 2018 and 2017, Generation had net payments of approximately $36 million and $8 million, respectively, related to purchases and sales of options. The level of option activity in a given period may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.
ComEd
During each of the six months ended June 30, 2018 and 2017, ComEd posted approximately $15 million and $13 million of cash collateral with PJM, respectively.  As of June 30, 2018 and 2017, ComEd had approximately $66 million and $36 million cash collateral posted with PJM, respectively. ComEd’s total collateral posted with PJM has increased year over year primarily due to an increase in ComEd’s peak market activity with PJM.
See Note 18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information regarding changes in non-cash operating activities.
Cash Flows from Investing Activities
Cash flows usedThe following table provides a summary of the change in cash provided by (used in) investing activities for the sixthree months ended June 30,March 31, 2019 and 2018 and 2017 by Registrant were as follows: Registrant:
 Six Months Ended
June 30,
 2018
2017
Exelon$(3,846) $(3,981)
Generation(1,549) (1,349)
ComEd(1,009) (1,156)
PECO(406) (242)
BGE(428) (401)
PHI(627) (670)
Pepco(285) (292)
DPL(165) (191)
ACE(172) (175)

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Change - Cash Provided by (Used in)Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Capital expenditures$7
 $117
 $28
 $(5) $(34) $(100) $(17) $(13) $(65)
Proceeds from NDT fund sales, net106
 106
 —
 —
 —
 —
 —
 —
 —
Proceeds from sales of assets and businesses(71) (71) —
 —
 —
 —
 —
 —
 —
Other investing activities29
 30
 3
 —
 —
 1
 1
 —
 1
Net cash flows provided by (used in) investing activities$71
 $182
 $31
 $(5) $(34) $(99) $(16) $(13) $(64)
Significant investing cash flow impacts for the Registrants for sixthree months ended June 30,March 31, 2019 and 2018 and 2017 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 three months ended March 31, 2018, Exelon and Generation
During the six months ended June 30, 2018, Exelon had proceeds of $85$79 million relating to the sale of its interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution services.business.
During the six months ended June 30, 2018, Exelon had expenditures of $57 million relating to the acquisition of the Handley Generating Station.
During the six months ended June 30, 2017, Exelon had expenditures of $23 million and $182 million relating to the acquisitions of ConEdison Solutions and the FitzPatrick facility, respectively.
Capital Expenditure Spending
Generation
Generation has entered into several agreementsAs of March 31, 2019, there have been no material changes to acquire equity intereststhe Registrants’ projected capital expenditures as disclosed in privately held development stage entities which develop energy-related technologies.  The agreements contain a series of scheduled investment commitments, including in-kind service contributions. There are anticipated expenditures remaining to fund anticipated planned capitalLiquidity and operating needsCapital Resources of the associated companies.
Capital expenditures by Registrant for the six months ended June 30,Exelon 2018 and 2017 and projected amounts for the full year 2018 are as follows:Form 10-K.
 
Projected
Full Year
2018(a)
 Six Months Ended
June 30,
 2018 2017
Exelon$7,900
(b) 
$3,807
 $3,845
Generation2,350
 1,298
 1,189
ComEd(c)
2,125
 1,026
 1,168
PECO850
 411
 367
BGE1,000
 434
 405
PHI1,550
(d) 
629
 671
Pepco700
 287
 291
DPL400
 166
 192
ACE425
 170
 175
_________
(a)Total projected capital expenditures do not include adjustments for non-cash activity.
(b)Includes corporate operations, BSC, and PHISCO rounded to the nearest $25 million.
(c)The capital expenditures and 2018 projections include approximately $83 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over a ten-year period, through 2021, to modernize and storm-harden its distribution system and to implement smart grid technology.
(d)Includes PHISCO rounded to the nearest $25 million.
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

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Generation
Approximately 40% and 11% of the projected 2018 capital expenditures at Generation are for the acquisition of nuclear fuel, and the construction of new natural gas plant and solar facilities, respectively, with the remaining amounts reflecting investment in renewable energy and additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that they will fund capital expenditures with internally generated funds and borrowings.
ComEd, PECO, BGE, Pepco, DPL and ACE
Projected 2018 capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as ComEd’s reliability related investments required under EIMA, and the Utility Registrants' construction commitments under PJM’s RTEP.
The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to transmission owners that recommended the Utility Registrants perform assessments of their transmission lines. ComEd, PECO and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd and PECO will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s and PECO’s forecasted 2018 capital expenditures above reflect capital spending for remediation to be completed through 2019. DPL and ACE are complete with their assessments and BGE and Pepco have substantially completed their assessments and thus do not expect significant capital expenditures related to this guidance in 2018.
The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent.
Cash Flows from Financing Activities
Cash flowsThe following table provides a summary of the change in cash provided by (used in) financing activities for the sixthree months ended June 30,March 31, 2019 and 2018 and 2017 by Registrant were as follows: Registrant:
 Six Months Ended
June 30,
 2018 2017
Exelon$(185) $983
Generation(518) 358
ComEd406
 361
PECO(100) (144)
BGE(46) (100)
PHI298
 245
Pepco98
 274
DPL88
 (43)
ACE105
 2
Change - Cash Provided by (Used in)Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Changes in short-term borrowings, net$(186) $(165) $5
 $(220) $103
 $90
 $31
 $10
 $49
Long-term debt, net161
 (20) —
 175
 —
 7
 —
 4
 4
Changes in Exelon intercompany money pool—
 (100) —
 (194) —
 (13) —
 —
 —
Dividends paid on common stock(19) —
 (13) 197
 (4) —
 1
 (5) (3)
Distributions to member—
 (37) —
 —
 —
 (57) —
 —
 —
Contributions from parent/member—
 —
 (50) 145
 —
 19
 14
 —
 5
Other financing activities55
 3
 —
 5
 —
 —
 —
 —
 —
Net cash flows provided by (used in) financing activities$11
 $(319) $(58) $108
 $99
 $46
 $46
 $9
 $55
Significant financing cash flow impacts for the Registrants for the three months ended March 31, 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.

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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 Contentsdividends 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 ofon the Registrants’ debt issuances.
Dividends
Cash dividend payments and distributions duringDuring the sixthree months ended June 30, 2018 and 2017 by Registrant were as follows:March 31, 2019, the following long-term debt was retired and/or redeemed:
 Six Months Ended
June 30,
 2018 2017
Exelon$666
 $607
Generation377
 330
ComEd229
 211
PECO293
 144
BGE105
 99
PHI109
 131
Pepco50
 58
DPL40
 54
ACE19
 22
Company Type Interest Rate Maturity Amount
Generation Antelope Valley DOE Nonrecourse Debt 2.33% - 3.56%
 January 5, 2037 $5
Generation Kennett Square Capital Lease 7.83% September 20, 2020 $1
Generation Continental Wind Nonrecourse Debt 6.00% February 28, 2033 $18
Generation Pollution control notes 2.50% March 1, 2019 $23
ComEd First Mortgage Bonds 2.15% January 15, 2019 $300
ACE Transition Bonds 5.55% October 20, 2023 $4
Antelope Valley’s nonrecourse debt of $502 million was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets as of March 31, 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 sixthree months ended June 30, 2018March 31, 2019 and for the thirdsecond quarter of 20182019 were as follows:
Period Declaration Date Shareholder of Record Date Dividend Payable Date 
Cash per Share(a)
First Quarter 2018 January 30, 2018 February 15, 2018 March 9, 2018 $0.3450
Second Quarter 2018 May 1, 2018 May 15, 2018 June 8, 2018 $0.3450
Third Quarter 2018 July 24, 2018 August 15, 2018 September 10, 2018 $0.3450
Period Declaration Date Shareholder of Record Date Dividend Payable Date 
Cash per Share(a)
First Quarter 2019 February 5, 2019 February 20, 2019 March 8, 2019 $0.3625
Second Quarter 2019 April 30, 2019 May 15, 2019 June 10, 2019 $0.3625
_________
(a)Exelon's Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.

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Short-Term Borrowings
Short-term borrowings incurred (repaid) during the six months ended June 30, 2018 and 2017 by Registrant were as follows:
 Six Months Ended
June 30,
 2018 2017
Exelon$325
 $488
Generation—
 15
ComEd320
 389
PECO50
 —
BGE59
 40
PHI(103) (455)
Pepco(26) (23)
DPL(216) 25
ACE139
 42
Contributions from Parent/Member
Contributions received from Parent/Member for the six months ended June 30, 2018 and 2017 by Registrant were as follows:
 Six Months Ended
June 30,
 2018 2017
ComEd(a)(b)
$225
 $184
PECO(b)
41
 —
PHI(b)
235
 751
Pepco(c)
85
 161
DPL(c)
150
 —
_________
(a)Additional contributions from parent or external debt financing may be required as a result of increased capital investment in infrastructure improvements and modernization pursuant to EIMA and transmission upgrades.
(b)Contribution paid by Exelon.
(c)Contribution paid by PHI.2020.
Other
For the sixthree months ended June 30, 2018,March 31, 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
The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include $9.5$9.8 billion in aggregate total commitments of which $8.0 billion was available as of June 30, 2018, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper market during the secondfirst quarter of 20182019 to fund their

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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 20172018 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 June 30, 2018,March 31, 2019, it would have been required to provide incremental collateral of $1.5$1.9 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 its currentthe $4.4 billion of available credit facility capacitiescapacity of $4.4 billion.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 June 30, 2018March 31, 2019 and available credit facility capacity prior to any incremental collateral at June 30, 2018:March 31, 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$9
 $—
 $998
$8
 $—
 $997
PECO1
 20
 600
1
 34
 600
BGE12
 36
 599
12
 46
 600
Pepco11
 —
 300
11
 —
 292
DPL4
 11
 300
5
 14
 300
ACE—
 —
 300
—
 —
 300
_________
(a)
Represents incremental collateral related to natural gas procurementprocurement 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.

TableSee 11 — Debt and Credit Agreements and Note 16 — Commitments and Contingencies of Contents

The following table reflectsthe Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ commercial paper programs supported byshort-term borrowing activity.
See Note 13 — Debt and Credit Agreements and Note 22 — Commitments and Contingencies of the revolving credit agreements and bilateral credit agreements at June 30, 2018:
Commercial Paper Programs
Commercial Paper Issuer 
Maximum Program Size(a)(b)
 Outstanding Commercial Paper at
June 30, 2018		 Average Interest Rate on Commercial Paper Borrowings for the Six Months Ended June 30, 2018
Exelon Corporate $600
 $—
 1.92%
Generation 5,300
 —
 1.94%
ComEd 1,000
 320
 2.09%
PECO 600
 50
 2.23%
BGE 600
 136
 2.08%
Pepco 500
 —
 2.18%
DPL 500
 —
 2.07%
ACE 350
 122
 2.10%
_________
(a)Excludes $545 million bilateral credit facilities that do not back Generation's commercial paper program.
(b)Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $34 million, $34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expireExelon 2018 Form 10-K for additional information on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of June 30, 2018, letters of credit issued under these agreements for Generation and BGE totaled $5 million and $2 million, respectively.

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In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of outstanding commercial paper does not reduce available capacity under a Registrant’s credit facility, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility. At June 30, 2018, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:
Borrower Facility Type 
Aggregate Bank
Commitment(a)(b)(c)
 
Facility
Draws
 
Outstanding
Letters of
Credit(c)
 Available Capacity at
June 30, 2018
Actual 
To Support
Additional
Commercial
Paper(b)(d)
Exelon Corporate Syndicated Revolver $600
 $—
 $24
 $576
 $576
Generation Syndicated Revolver 5,300
 —
 1,113
 4,187
 4,187
Generation Bilaterals 545
 —
 356
 189
 —
ComEd Syndicated Revolver 1,000
 —
 2
 998
 678
PECO Syndicated Revolver 600
 —
 —
 600
 550
BGE Syndicated Revolver 600
 —
 1
 599
 463
Pepco Syndicated Revolver 300
 —
 —
 300
 300
DPL Syndicated Revolver 300
 —
 —
 300
 300
ACE Syndicated Revolver 300
 —
 —
 300
 178
_________
(a)Excludes $128 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of June 30, 2018, letters of credit issued under these agreements for Generation and BGE totaled $5 million and $2 million, respectively.
(b)Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the Registrant is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility
(c)Excludes nonrecourse debt letters of credit, see Note 13 — Debt and Credit Agreements in the Exelon 2017 Form 10-K for additional information.
(d)Excludes $545 million bilateral credit facilities that do not back Generation’s commercial paper program.
As of June 30, 2018, there were no borrowings under Generation's bilateralRegistrants’ credit facilities.

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Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table:
 Exelon Corporate Generation ComEd PECO BGE Pepco DPL ACE
Prime based borrowings27.5 27.5 7.5 0.0 0.0 7.5
 7.5
 7.5
LIBOR-based borrowings127.5 127.5 107.5 90.0 100.0 107.5
 107.5
 107.5
The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 90 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower.
Each revolving credit agreement for Exelon Corporate, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The following table summarizes the minimum thresholds reflected in the credit agreements for the six months ended June 30, 2018:
Exelon CorporateGenerationComEdPECOBGEPepcoDPLACE
Credit agreement threshold2.50 to 13.00 to 12.00 to 12.00 to 12.00 to 12.00 to 12.00 to 12.00 to 1
At June 30, 2018, the interest coverage ratios at the Registrants were as follows:
 Exelon Generation ComEd PECO BGE Pepco DPL ACE
Interest coverage ratio6.93
 10.89
 12.33
 7.54
 10.29
 6.09 8.08 5.35
An event of default under Exelon, Generation, ComEd, PECO or BGE's indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation will constitute an event of default under the Exelon Corporate credit facility. An event of default under Pepco, DPL or ACE's indebtedness will not constitute an event of default with respect to the other PHI Utilities under the PHI Utilities' combined credit facility.
The absence of a material adverse change in Exelon's or PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under any of the borrowers' credit agreement. None of the credit agreements include any rating triggers.
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.

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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 June 30, 2018,March 31, 2019, are presented in the following table:
Exelon Intercompany Money Pool During the Three Months Ended June 30, 2018 As of June 30, 2018 During the Three Months Ended March 31, 2019 As of March 31, 2019
Contributed (Borrowed) 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
Exelon Corporate $674
 $—
 $260
 $467
 $—
 $189
Generation 225
 (54) 185
 —
 (235) —
PECO —
 (420) (233) 15
 (10) —
BSC —
 (379) (261) —
 (383) (248)
PHI Corporate —
 (33) (8) —
 (9) (1)
PCI 57
 (1) 57
 60
 —
 60
PHI Intercompany Money Pool During the Three Months Ended June 30, 2018 As of June 30, 2018
Contributed (Borrowed) 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
PHI Corporate $33
 $(1) $15
PHISCO 13
 (31) (13)
Investments in Nuclear Decommissioning Trust Funds
Exelon, Generation and CENG maintain trust funds, as required by the NRC, to fund certain costs of decommissioning nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with Generation’s NDT fund investment policy. Generation’s and CENG’s investment policies establish limits on the concentration of holdings in any one company and also in any one industry. See Note 13 —Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.
PHI Intercompany Money Pool During the Three Months Ended March 31, 2019 As of March 31, 2019
Contributed (Borrowed) 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
PHI Corporate $9
 $—
 $—
PHISCO 4
 (7) 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. 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

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other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

Regulatory Authorizations
ComEd, PECO, BGE, Pepco, DPL and ACE are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
 As of June 30, 2018 As of March 31, 2019
 
Short-term Financing Authority(a)
 
Remaining Long-term Financing Authority(a)
 
Short-term Financing Authority(a)
 
Remaining Long-term Financing Authority(a)
Commission Expiration Date AmountCommission Expiration Date AmountCommission Expiration Date AmountCommission Expiration Date Amount
ComEd(b)
 FERC December 31, 2019 $2,500
 ICC 2019 $583
 FERC December 31, 2019 $2,500
 ICC 2019 & 2021 $1,133
PECO(c) FERC December 31, 2019 1,500
 PAPUC December 31, 2018 950
 FERC December 31, 2019 1,500
 PAPUC December 31, 2021 1,900
BGE FERC December 31, 2019 700
 MDPSC N/A 700
 FERC December 31, 2019 700
 MDPSC N/A 400
Pepco FERC December 31, 2019 500
 MDPSC / DCPSC December 31, 2020 500
 FERC December 31, 2019 500
 MDPSC / DCPSC December 31, 2020 400
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 350
 NJBPU December 31, 2019 350
 NJBPU December 31, 2019 —
_________
(a)Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.
(b)ComEd had $440 million available in long-term debt refinancing authority and $143$693 million available in new money long-term debt financing authority from the ICC as of June 30, 2018March 31, 2019 and has an expiration date of June 1, 2019 and MarchAugust 1, 2019,2021, respectively.
(c)On April 9, 2018, ComEd filed an application18, 2019, ACE received approval from the NJBPU for $1.5 billion in new money$350 million long-term debt financing authority, from the ICC and received approvalexpiring on July 25, 2018.December 31, 2020.

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 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 20172018 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 20172018 Form 10-K.

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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 20172018 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 20182019 through 2020.2021.
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 June 30, 2018,March 31, 2019, the percentage of expected generation hedged is 97%-100%90%-93%, 71%-74%64%-67% and 41%-44%38%-41% for 2018, 2019, 2020 and 2020,2021, 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 facilitiesgeneration 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 reduction in the annual average around-the-clock energy price based on June 30, 2018March 31, 2019 market conditions and hedged position would be an increasea decrease in pre-tax net income of approximately $13$25 million for 2018 and decreases of approximately $269, $279 million and $549$551 million, respectively, for 2019, 2020 and 2020.2021. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant.

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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.
Retail Competition
Constellation competes for retail customers in a competitive environment, which affects the margins that Generation can earn and the volumes that it is able to serve. In periods of sustained low natural gas and power prices and low market volatility, retail competitors can aggressively pursue market share because the barriers to entry can be low and wholesale generators (including Generation) use their retail hedge generation output. Increased or more aggressive competition could adversely affect Generation's overall gross margins and profitability.
Proprietary Trading Activities
Proprietary trading portfolio activity for the sixthree months ended June 30, 2018March 31, 2019 resulted in $35$4 million of pre-tax gains due to net mark-to-market gains of $17$2 million and realized gains of $18$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 purchasepurchased 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 59%62% of Generation’s uranium concentrate requirements from 20182019 through 20222023 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.statements.
ComEd
ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014.
ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which is further discussed in Note 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

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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. SeeFor additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on these contracts.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 qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.
PECO, BGE and DPL have also executed derivative natural gas contracts, which either qualify for the normal purchases and normal sales exception or have no mark-to-market balances because the derivatives are index priced, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their results of operations or financial position.statements.
PECO, BGE, Pepco, DPL and ACE do not enter intoexecute derivatives for speculative or proprietary trading purposes. SeeFor additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on these contracts.Statements.
Trading and Non-Trading Marketing Activities
The following tables detailtable detailing Exelon’s, Generation’s ComEd’s, PHI's and DPL'sComEd’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).

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The following table provides detail on changes in Exelon’s, Generation’s ComEd’s, PHI's and DPL'sComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, 20172018 to June 30, 2018.March 31, 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 June 30, 2018March 31, 2019 and December 31, 2017.2018.
Exelon Generation ComEd PHI DPLExelon Generation ComEd
Total mark-to-market energy contract net assets (liabilities) at December 31, 2017(a)
$667
 $923
 $(256) $—
 $—
Total mark-to-market energy contract net assets (liabilities) at December 31, 2018(a)
$299
 $548
 $(249)
Total change in fair value during 2018 of contracts recorded in results of operations194
 194
 —
 —
 —
(87) (87) —
Reclassification to realized of contracts recorded in results of operations(354) (354) —
 —
 —
69
 69
 —
Changes in fair value — recorded through regulatory assets and liabilities(b)
5
 —
 4
 1
 1
9
 —
 9
Changes in allocated collateral(85) (84) —
 (1) (1)135
 135
 —
Net option premium paid/(received)36
 36
 —
 —
 —
(6) (6) —
Option premium amortization7
 7
 —
 —
 —
(37) (37) —
Total mark-to-market energy contract net assets (liabilities) at June 30,2018(a)
$470
 $722
 $(252) $—
 $—
Upfront payments and amortizations(c)
(45) (45) —
Total mark-to-market energy contract net assets (liabilities) at March 31, 2019(a)
$337
 $577
 $(240)
_________
(a)Amounts are shown net of collateral paid to and received from counterparties.
(b)For ComEd, and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of June 30, 2018,March 31, 2019, ComEd recorded a regulatory liability of $252$240 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the sixthree months ended June 30, 2018,March 31, 2019, ComEd also recorded $6$9 million of decreases in fair value and an increase for realized losses due to settlements of $10$80 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.

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Exelon
Maturities Within Total Fair
Value		Maturities Within Total Fair
Value
2018 2019 2020 2021 2022 2023 and Beyond 2019 2020 2021 2022 2023 2024 and Beyond 
Normal Operations, Commodity derivative contracts(a)(b):
                          
Actively quoted prices (Level 1)$4
 $(36) $(30) $(2) $(5) $13
 $(56)$(11) $(22) $(1) $(5) $14
 $—
 $(25)
Prices provided by external sources (Level 2)34
 (7) 12
 2
 —
 —
 41
67
 15
 22
 (1) —
 —
 103
Prices based on model or other valuation methods (Level 3)(c)
283
 289
 73
 (24) (61) (75) 485
152
 210
 36
 (39) (17) (83) 259
Total$321
 $246
 $55
 $(24) $(66) $(62) $470
$208
 $203
 $57
 $(45) $(3) $(83) $337
_________
(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 $382$492 million at June 30, 2018.March 31, 2019.
(c)Includes ComEd’s net liabilitiesassets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Generation
Maturities Within Total Fair
Value		Maturities Within Total Fair
Value
2018 2019 2020 2021 2022 2023 and Beyond 2019 2020 2021 2022 2023 2024 and Beyond 
Normal Operations, Commodity derivative contracts(a)(b):
                          
Actively quoted prices (Level 1)$4
 $(36) $(30) $(2) $(5) $13
 $(56)$(11) $(22) $(1) $(5) $14
 $—
 $(25)
Prices provided by external sources (Level 2)34
 (7) 12
 2
 —
 —
 41
67
 15
 22
 (1) —
 —
 103
Prices based on model or other valuation methods (Level 3)295
 313
 97
 —
 (37) 69
 737
172
 235
 61
��(14) 9
 36
 499
Total$333
 $270
 $79
 $—
 $(42) $82
 $722
$228
 $228
 $82
 $(20) $23
 $36
 $577
_________
(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 $382$492 million at June 30, 2018.March 31, 2019.
ComEd
Maturities Within Total Fair
Value		Maturities Within Total Fair
Value
2018 2019 2020 2021 2022 2023 and Beyond 2019 2020 2021 2022 2023 2024 and Beyond 
Commodity derivative contracts(a):
                          
Prices based on model or other valuation methods (Level 3)$(12) $(24) $(24) $(24) $(24) $(144) $(252)$(20) $(25) $(25) $(25) $(26) $(119) $(240)
_________
(a)Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

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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 informationdiscussion of credit risk, collateral and contingent-relatedcontingent related features.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchases and normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2018.March 31, 2019. The tables further disaggregatedelineate 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 $47$36 million, $23$31 million,, $23 $27 million, $31$37 million, $5 million and $4 million as of June 30, 2018,March 31, 2019, respectively.
Rating as of June 30, 2018 Total  Exposure Before Credit Collateral 
Credit
Collateral(a)
 
Net
Exposure
 
Number of
Counterparties
Greater than 10%
of Net Exposure
 
Net Exposure of
Counterparties
Greater than
10% of Net
Exposure
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
Investment grade $823
 $—
 $823
 1
 $206
 $819
 $11
 $808
 1
 $135
Non-investment grade 90
 30
 60
 

 

 86
 39
 47
 

 

No external ratings                    
Internally rated — investment grade 228
 —
 228
 

 

 162
 —
 162
 

 

Internally rated — non-investment grade 78
 13
 65
 

 

 87
 7
 80
 

 

Total $1,219
 $43
 $1,176
 1
 $206
 $1,154
 $57
 $1,097
 1
 $135
  Maturity of Credit Risk Exposure
Rating as of June 30, 2018 
Less than
2 Years
 2-5 Years 
Exposure
Greater than
5 Years
 
Total Exposure
Before Credit
Collateral
Investment grade $774
 $47
 $2
 $823
Non-investment grade 82
 8
 —
 90
No external ratings        
Internally rated — investment grade 165
 33
 30
 228
Internally rated — non-investment grade 79
 (1) —
 78
Total $1,100
 $87
 $32
 $1,219

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  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
Investment grade $760
 $47
 $12
 $819
Non-investment grade 87
 (1) —
 86
No external ratings        
Internally rated — investment grade 110
 26
 26
 162
Internally rated — non-investment grade 76
 5
 6
 87
Total $1,033
 $77
 $44
 $1,154
Net Credit Exposure by Type of Counterparty As of
June 30, 2018		 As of
March 31, 2019
Financial institutions $97
 $13
Investor-owned utilities, marketers, power producers 627
 762
Energy cooperatives and municipalities 392
 287
Other 60
 35
Total $1,176
 $1,097
_________
(a)As of June 30, 2018,March 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $22$37 million of cash and $21$19 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 20172018 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 (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 1716 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.
Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.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. Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information.
The Utility Registrants
As of June 30, 2018,March 31, 2019, ComEd held $5$11 million in collateral from suppliers in association with energy procurement contracts, $14$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

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gas procurement contracts but was holding an immaterial amount of collateral under its natural gas procurement contracts. PECO, Pepco and DPL were not required to post collateral under their energy and/or natural gas procurement contracts, but were holding an immaterial amount of collateral under their respective electric supply procurement contracts. PECO and ACE were not required to post collateral under their energy and/or natural gas procurement contracts. 
See Note 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 areis no spot energy markets,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’ results of operations, cash flows and financial positions.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)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps which are typically designated as fair value hedges, to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At June 30, 2018,March 31, 2019, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had $624$619 million of notional amounts of floating-to-fixed hedges outstanding. Assuming the fair value and interest rate hedges are 100% effective, aA hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $3$1 million decrease in Exelon Consolidated pre-tax income for the sixthree months ended June 30, 2018.March 31, 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 June 30, 2018,March 31, 2019, Generation’s decommissioning trustNDT funds are reflected at fair value onin 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

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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 $590$587 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information of equity price risk as a result of the current capital and credit market conditions.
Item 4.    Controls and Procedures
During the secondfirst quarter of 2018,2019, 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 June 30, 2018,March 31, 2019, the principal executive officer and principal financial officer of each of Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. All Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There

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 have been no changes in internal control over financial reporting that occurred during the secondfirst quarter of 20182019 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.

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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 20172018 Form 10-K and (b) Notes 6 — Regulatory Matters and 1716 — 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 June 30, 2018,March 31, 2019, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 20172018 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 adopted Amended and Restated Bylaws, and PHI entered into an Amended and Restated Limited Liability Company Agreement. The amendments are primarily intended to align 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.

TableThis summary is qualified by reference to the complete text of Contents
the BGE and PECO Amended and Restated Bylaws, and the PHI Amended and Restated Limited Liability Company Agreement, attached as Exhibits 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
Amended and Restated ArticlesBylaws of Incorporation of Exelon Corporation, as amended on July 24, 2018 (File No. 001-16169, Form 8-K dated July 27, 2018, Exhibit 3.1)Baltimore Gas and Electric Company
  
3.2
Amended and Restated Bylaws of Exelon Corporation, as amended on July 24, 2018 (File No. 001-16169, Form 8-K dated July 27, 2018, Exhibit 3.2)PECO Energy Company
3.3
Amended and Restated Limited Liability Company Agreement of Pepco Holdings LLC
  
4.1
Supplemental Indenture dated as of June 1, 2018,February 7, 2019 from Delmarva Power & LightCommonwealth Edison Company to The BankBNY Mellon Trust Company of New York Mellon,Illinois, as trustee, and D. G. Donovan, as co-trustee (File No. 001-01405,001-01839, Form 8-K dated June 21, 2018,February 19, 2019, Exhibit 4.2)4.1)
  
4.2
One Hundred and Twenty-Second Supplemental Indenture, dated as of June 1, 2018, from Potomac ElectricApril 3, 2019, between Delmarva Power & Light Company toand The Bank of New York Mellon, as trustee (File No. 001-01072, Form 8-K dated June 21, 2018, Exhibit 4.2)
10.1
Purchase Agreement, dated June 8, 2018 among Delmarva Power & Light Company and the purchasers signatory thereto (File No. 001-01405, Form 8-K dated June 21, 2018, Exhibit 1.1)
10.2
Purchase Agreement, dated June 8, 2018 among Potomac Electric Power Company and the purchasers signatory thereto (File No. 001-01072, Form 8-K dated June 21, 2018, Exhibit 1.1)
10.3
Letter Agreement, dated May 7, 2018 between Exelon Corporation and Denis P. O'Brien
10.4
Letter Agreement, dated May 7, 2018, between Exelon Corporation and Jonathan W. Thayer
  
101.INSXBRL Instance
  
101.SCHXBRL Taxonomy Extension Schema
  
101.CALXBRL Taxonomy Extension Calculation
  
101.DEFXBRL Taxonomy Extension Definition
  
101.LABXBRL Taxonomy Extension Labels
  
101.PREXBRL Taxonomy Extension Presentation

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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 June 30, 2018March 31, 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 Phillip S. BarnettRobert J. Stefani for PECO Energy Company
  
31-9
— Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company
  
31-10
— Filed by David M. Vahos for Baltimore Gas and Electric Company
  
31-11
— Filed by David M. Velazquez for Pepco Holdings LLC
  
31-12
— Filed by Robert M. AikenPhillip S. Barnett for Pepco Holdings LLC
  
31-13
— Filed by David M. Velazquez for Potomac Electric Power Company
  
31-14
— Filed by Robert M. AikenPhillip S. Barnett for Potomac Electric Power Company
  
31-15
— Filed by David M. Velazquez for Delmarva Power & Light Company
  
31-16
— Filed by Robert M. AikenPhillip S. Barnett for Delmarva Power & Light Company
  
31-17
— Filed by David M. Velazquez for Atlantic City Electric Company
  
31-18
— Filed by Robert M. AikenPhillip S. Barnett for Atlantic City Electric Company

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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 June 30, 2018March 31, 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 Phillip S. BarnettRobert J. Stefani for PECO Energy Company
  
32-9
— Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company
  
32-10
— Filed by David M. Vahos for Baltimore Gas and Electric Company
  
32-11
— Filed by David M. Velazquez for Pepco Holdings LLC
  
32-12
— Filed by Robert M. AikenPhillip S. Barnett for Pepco Holdings LLC
  
32-13
— Filed by David M. Velazquez for Potomac Electric Power Company
  
32-14
— Filed by Robert M. AikenPhillip S. Barnett for Potomac Electric Power Company
  
32-15
— Filed by David M. Velazquez for Delmarva Power & Light Company
  
32-16
— Filed by Robert M. AikenPhillip S. Barnett for Delmarva Power & Light Company
  
32-17
— Filed by David M. Velazquez for Atlantic City Electric Company
  
32-18
— Filed by Robert M. AikenPhillip S. Barnett for Atlantic City Electric Company

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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/    CHRISTOPHERCHRISTOPHER M. CRANE
CRANE		 
/s/    JOSEPHJOSEPH 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/    FABIANFABIAN E. SOUZA
SOUZA		  
Fabian E. Souza  
Senior Vice President and Corporate Controller
(Principal Accounting Officer)
  
AugustMay 2, 2018

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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/    KENNETHKENNETH W. CORNEW
CORNEW		 
/s/    BRYANBRYAN P. WRIGHT
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/    MATTHEWMATTHEW N. BAUER
BAUER		  
Matthew N. Bauer  
Vice President and Controller
(Principal Accounting Officer)
  
AugustMay 2, 2018

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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
JOSEPH DOMINGUEZ		 
/s/    JEANNEJEANNE M. JONES
JONES
Joseph Dominguez Jeanne M. Jones
Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
   
/s/    GERALDGERALD J. KOZEL
KOZEL		  
Gerald J. Kozel  
Vice President and Controller
(Principal Accounting Officer)
  
AugustMay 2, 20182019

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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/    MICHAELMICHAEL A. INNOCENZO
INNOCENZO		 
/s/    PHILLIP S. BARNETT
ROBERT J. STEFANI
Michael A. Innocenzo Phillip S. BarnettRobert J. Stefani
President and Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
   
/s/    SCOTTSCOTT A. BAILEY
BAILEY		  
Scott A. Bailey  
Vice President and Controller
(Principal Accounting Officer)
  
AugustMay 2, 20182019


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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/    CALVINCALVIN G. BUTLER, JR.
BUTLER, JR.		 
/s/    DAVIDDAVID M. VAHOS
VAHOS
Calvin G. Butler, Jr. David M. Vahos
Chief Executive Officer
(Principal Executive Officer)
 Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
   
 /s/ ANDREWANDREW W. HOLMES
HOLMES		  
Andrew W. Holmes  
Vice President and Controller
(Principal Accounting Officer)
  
AugustMay 2, 20182019


Table of Contents

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/ DAVIDDAVID M. VELAZQUEZ
VELAZQUEZ		 
/s/    ROBERT M. AIKEN
PHILLIP S. BARNETT
David M. Velazquez Robert M. AikenPhillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and ControllerTreasurer
(Principal Financial Officer)
   
/s/ ROBERTROBERT M. AIKEN
AIKEN		  
Robert M. Aiken  
Vice President and Controller
(Principal Accounting Officer)
  
AugustMay 2, 20182019


Table of Contents

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/ DAVIDDAVID M. VELAZQUEZ
VELAZQUEZ		 
/s/    ROBERT M. AIKEN
PHILLIP S. BARNETT
David M. Velazquez Robert M. AikenPhillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)		 
Senior Vice President, Chief Financial Officer and ControllerTreasurer
(Principal Financial Officer)
   
/s/ ROBERTROBERT M. AIKEN
AIKEN		  
Robert M. Aiken  
Vice President and Controller
(Principal Accounting Officer)		  
AugustMay 2, 20182019


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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/ DAVIDDAVID M. VELAZQUEZ
VELAZQUEZ		 
/s/    ROBERT M. AIKEN
PHILLIP S. BARNETT
David M. Velazquez Robert M. AikenPhillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)		 
Senior Vice President, Chief Financial Officer and ControllerTreasurer
(Principal Financial Officer)
   
/s/ ROBERTROBERT M. AIKEN
AIKEN		  
Robert M. Aiken  
Vice President and Controller
(Principal Accounting Officer)		  
AugustMay 2, 20182019


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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/ DAVIDDAVID M. VELAZQUEZ
VELAZQUEZ		 
/s/    ROBERT M. AIKEN
PHILLIP S. BARNETT
David M. Velazquez Robert M. AikenPhillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)		 
Senior Vice President, Chief Financial Officer and ControllerTreasurer
(Principal Financial Officer)
   
/s/ ROBERTROBERT M. AIKEN
AIKEN		  
Robert M. Aiken  
Vice President and Controller
(Principal Accounting Officer)		  
AugustMay 2, 20182019

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