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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 2020
or
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number
 
Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number
 
IRS Employer Identification Number
 
 
 
 
 
001-16169
 
EXELON CORPORATION
 
23-2990190
 
 
(a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago, Illinois 60680-5379
(800) 483-3220
 
 
 
 
 
 
 
333-85496
 
EXELON GENERATION COMPANY, LLC
 
23-3064219
 
 
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348-2473
(610) 765-5959
 
 
 
 
 
 
 
001-01839
 
COMMONWEALTH EDISON COMPANY
 
36-0938600
 
 
(an Illinois corporation)
440 South LaSalle Street
Chicago, Illinois 60605-1028
(312) 394-4321
 
 
 
 
 
 
 
000-16844
 
PECO ENERGY COMPANY
 
23-0970240
 
 
(a Pennsylvania corporation)
P.O. Box 8699
2301 Market Street
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000
 
 
 
 
 
 
 
001-01910
 
BALTIMORE GAS AND ELECTRIC COMPANY
 
52-0280210
 
 
(a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore, Maryland 21201-3708
(410) 234-5000
 
 
 
 
 
 
 
001-31403
 
PEPCO HOLDINGS LLC
 
52-2297449
 
 
(a Delaware limited liability company)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000
 
 
 
 
 
 
 
001-01072
 
POTOMAC ELECTRIC POWER COMPANY
 
53-0127880
 
 
(a District of Columbia and Virginia corporation)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000
 
 
 
 
 
 
 
001-01405
 
DELMARVA POWER & LIGHT COMPANY
 
51-0084283
 
 
(a Delaware and Virginia corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000
 
 
 
 
 
 
 
001-03559
 
ATLANTIC CITY ELECTRIC COMPANY
 
21-0398280
 
 
(a New Jersey corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000
 
 



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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  x  No  o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  x  No  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Exelon Corporation
Large Accelerated Filer
x
Accelerated Filer
☐
Non-accelerated Filer
☐
Smaller Reporting Company
☐
Emerging Growth Company
☐
Exelon Generation Company, LLC
Large Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated Filer
x
Smaller Reporting Company
☐
Emerging Growth Company
☐
Commonwealth Edison Company
Large Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated Filer
x
Smaller Reporting Company
☐
Emerging Growth Company
☐
PECO Energy Company
Large Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated Filer
x
Smaller Reporting Company
☐
Emerging Growth Company
☐
Baltimore Gas and Electric Company
Large Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated Filer
x
Smaller Reporting Company
☐
Emerging Growth Company
☐
Pepco Holdings LLC
Large Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated Filer
x
Smaller Reporting Company
☐
Emerging Growth Company
☐
Potomac Electric Power Company
Large Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated Filer
x
Smaller Reporting Company
☐
Emerging Growth Company
☐
Delmarva Power & Light Company
Large Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated Filer
x
Smaller Reporting Company
☐
Emerging Growth Company
☐
Atlantic City Electric Company
Large Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated Filer
x
Smaller Reporting Company
☐
Emerging Growth Company
☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  ☐  No  x

The number of shares outstanding of each registrant’s common stock as of June 30, 2020 was:
Exelon Corporation Common Stock, without par value
974,503,895
Exelon Generation Company, LLC
not applicable
Commonwealth Edison Company Common Stock, $12.50 par value
127,021,354
PECO Energy Company Common Stock, without par value
170,478,507
Baltimore Gas and Electric Company Common Stock, without par value
1,000
Pepco Holdings LLC
not applicable
Potomac Electric Power Company Common Stock, $0.01 par value
100
Delmarva Power & Light Company Common Stock, $2.25 par value
1,000
Atlantic City Electric Company Common Stock, $3.00 par value
8,546,017


TABLE OF CONTENTS

 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

1

 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2

 
Page No.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

3
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
ACE Funding or ATF
 
Atlantic City Electric Transition Funding LLC
Antelope Valley
 
Antelope Valley Solar Ranch One
BSC
 
Exelon Business Services Company, LLC
CENG
 
Constellation Energy Nuclear Group, LLC
Constellation
 
Constellation Energy Group, Inc.
EGR IV
 
ExGen Renewables IV, LLC
EGRP
 
ExGen Renewables Partners, LLC
Exelon Corporate
 
Exelon in its corporate capacity as a holding company
FitzPatrick
 
James A. FitzPatrick nuclear generating station
NER
 
NewEnergy Receivables LLC
PCI
 
Potomac Capital Investment Corporation and its subsidiaries
PECO Trust III
 
PECO Capital Trust III
PECO Trust IV
 
PECO Energy Capital Trust IV
Pepco Energy Services
 
Pepco Energy Services, Inc. and its subsidiaries
PHI Corporate
 
PHI in its corporate capacity as a holding company
PHISCO
 
PHI Service Company
SolGen
 
SolGen, LLC
TMI
 
Three Mile Island nuclear facility

4
Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
 
 
Note "—" of the 2019 Form 10-K
 
Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2019 Annual Report on Form 10-K
AEC
 
Alternative 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
AMI
 
Advanced Metering Infrastructure
AOCI
 
Accumulated Other Comprehensive Income (Loss)
ARC
 
Asset Retirement Cost
ARO
 
Asset Retirement Obligation
BGS
 
Basic Generation Service
CBA
 
Collective Bargaining Agreement

CERCLA
 
Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CES
 
Clean Energy Standard
Clean Water Act
 
Federal Water Pollution Control Amendments of 1972, as amended
CODM
 
Chief operating decision maker(s)
D.C. Circuit Court
 
United States Court of Appeals for the District of Columbia Circuit
DC PLUG
 
District of Columbia Power Line Undergrounding Initiative
DCPSC
 
Public Service Commission of the District of Columbia
DOE
 
United States Department of Energy
DOEE
 
Department of Energy & Environment
DOJ
 
United States Department of Justice
DPP
 
Deferred Purchase Price
DPSC
 
Delaware Public Service Commission
EDF
 
Electricite de France SA and its subsidiaries
EIMA
 
Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EPA
 
United States Environmental Protection Agency
ERCOT
 
Electric Reliability Council of Texas
FASB
 
Financial Accounting Standards Board
FEJA
 
Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC
 
Federal Energy Regulatory Commission
FRCC
 
Florida Reliability Coordinating Council
FRR
 
Fixed Resource Requirement
GAAP
 
Generally Accepted Accounting Principles in the United States
GCR
 
Gas Cost Rate
GSA
 
Generation Supply Adjustment
IBEW
 
International Brotherhood of Electrical Workers

ICC
 
Illinois Commerce Commission
ICE
 
Intercontinental Exchange
 
 
 

5
Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
 
 
IPA
 
Illinois Power Agency
IRC
 
Internal Revenue Code
IRS
 
Internal Revenue Service
ISO
 
Independent System Operator
ISO-NE
 
Independent System Operator New England Inc.
LIBOR
 
London Interbank Offered Rate
MDE
 
Maryland Department of the Environment
MDPSC
 
Maryland Public Service Commission
MGP
 
Manufactured Gas Plant
MISO
 
Midcontinent Independent System Operator, Inc.
mmcf
 
Million Cubic Feet
MOPR
 
Minimum Offer Price Rule
MW
 
Megawatt
MWh
 
Megawatt hour
NDT
 
Nuclear Decommissioning Trust
NERC
 
North American Electric Reliability Corporation
NGX
 
Natural Gas Exchange
NJBPU
 
New Jersey Board of Public Utilities
Non-Regulatory Agreements Units
 
Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOSA
 
Nuclear Operating Services Agreement
NPNS
 
Normal Purchase Normal Sale scope exception
NRC
 
Nuclear Regulatory Commission
NYISO
 
New York Independent System Operator Inc.
NYMEX
 
New York Mercantile Exchange
NYPSC
 
New York Public Service Commission
OCI
 
Other Comprehensive Income
OIESO
 
Ontario Independent Electricity System Operator
OPEB
 
Other Postretirement Employee Benefits
PAPUC
 
Pennsylvania Public Utility Commission
PGC
 
Purchased Gas Cost Clause
PG&E
 
Pacific Gas and Electric Company
PJM
 
PJM Interconnection, LLC
POLR
 
Provider of Last Resort
PPA
 
Power Purchase Agreement
PPE
 
Property, plant and equipment
Price-Anderson Act
 
Price-Anderson Nuclear Industries Indemnity Act of 1957
PRP
 
Potentially Responsible Parties
PSDAR
 
Post-Shutdown Decommissioning Activities Report
PSEG
 
Public Service Enterprise Group Incorporated
REC
 
Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source

6
Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
 
 
RNF
 
Revenues Net of Purchased Power and Fuel Expense
Regulatory Agreement Units
 
Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RFP
 
Request for Proposal
Rider
 
Reconcilable Surcharge Recovery Mechanism
RMC
 
Risk Management Committee
ROE
 
Return on equity
ROU
 
Right-of-use
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)
SNF
 
Spent Nuclear Fuel
SOS
 
Standard Offer Service
SPFPA
 
International Union, Security, Police and Fire Professionals of America

TCJA
 
Tax Cuts and Jobs Act
Transition Bonds
 
Transition Bonds issued by ACE Funding
VIE
 
Variable Interest Entity
WECC
 
Western Electric Coordinating Council
ZEC
 
Zero Emission Credit, or Zero Emission Certificate
ZES
 
Zero Emission Standard

7
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 including among others those related to the expected or potential impact of the novel coronavirus (COVID-19) pandemic, and the related responses of various governments and regulatory bodies, our customers, and the company, on our business, financial condition and results of operations; any such forward-looking statements, whether concerning the COVID-19 pandemic or otherwise, involve risks, assumptions and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic and financial performance, are intended to identify such forward-looking statements.
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 2019 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors; (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, ITEM 1. Financial Statements: Note 14, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.
Investors are cautioned not to place undue reliance on these forward-looking statements, whether written or oral, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE TO FIND MORE INFORMATION
The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and the Registrants' website at www.exeloncorp.com. Information contained on the Registrants' website shall not be deemed incorporated into, or to be a part of, this Report.

8
Table of Contents

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements

9
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)
2020
 
2019
 
2020
 
2019
Operating revenues
 
 
 
 
 
 
 
Competitive businesses revenues
$
3,611

 
$
3,959

 
$
8,014

 
$
8,938

Rate-regulated utility revenues
3,832

 
3,743

 
8,108

 
8,247

Revenues from alternative revenue programs
(122
)
 
(13
)
 
(55
)
 
(19
)
Operating revenue from affiliates
1

 
—

 
2

 
—

Total operating revenues
7,322

 
7,689

 
16,069

 
17,166

Operating expenses
 
 
 
 
 
 
 
Competitive businesses purchased power and fuel
1,945

 
2,289

 
4,655

 
5,493

Rate-regulated utility purchased power and fuel
979

 
936

 
2,136

 
2,285

Operating and maintenance
2,433

 
2,159

 
4,637

 
4,347

Depreciation and amortization
1,001

 
1,079

 
2,023

 
2,154

Taxes other than income taxes
411

 
418

 
847

 
863

Total operating expenses
6,769


6,881


14,298


15,142

Gain on sales of assets and businesses
12

 
33

 
13

 
36

Operating income
565


841


1,784


2,060

Other income and (deductions)
 
 
 
 

 

Interest expense, net
(421
)
 
(403
)
 
(824
)
 
(800
)
Interest expense to affiliates
(6
)
 
(6
)
 
(13
)
 
(13
)
Other, net
656

 
212

 
(68
)
 
679

Total other income and (deductions)
229


(197
)

(905
)

(134
)
Income before income taxes
794

 
644

 
879

 
1,926

Income taxes
219

 
144

 
(75
)
 
454

Equity in losses of unconsolidated affiliates
(1
)
 
(6
)
 
(4
)
 
(12
)
Net income
574


494


950


1,460

Net income (loss) attributable to noncontrolling interests
53

 
10

 
(153
)
 
69

Net income attributable to common shareholders
$
521


$
484


$
1,103


$
1,391

Comprehensive income, net of income taxes
 
 
 
 
 
 
 
Net income
$
574

 
$
494

 
$
950

 
$
1,460

Other comprehensive income (loss), net of income taxes
 
 
 
 
 
 
 
Pension and non-pension postretirement benefit plans:
 
 
 
 
 
 
 
Prior service benefit reclassified to periodic benefit cost
(10
)
 
(16
)
 
(20
)
 
(32
)
Actuarial loss reclassified to periodic benefit cost
47

 
36

 
94

 
74

Pension and non-pension postretirement benefit plan valuation adjustment
2

 
—

 
(5
)
 
(39
)
Unrealized loss on cash flow hedges
—

 
—

 
(1
)
 
—

Unrealized loss on investments in unconsolidated affiliates
—

 
(2
)
 
—

 
(4
)
Unrealized gain (loss) on foreign currency translation
2

 
3

 
(6
)
 
4

Other comprehensive income
41


21


62


3

Comprehensive income
615


515


1,012


1,463

Comprehensive income (loss) attributable to noncontrolling interests
53

 
9

 
(153
)
 
67

Comprehensive income attributable to common shareholders
$
562

 
$
506

 
$
1,165

 
$
1,396

 
 
 
 
 
 
 
 
Average shares of common stock outstanding:
 
 
 
 
 
 
 
Basic
976

 
972

 
975

 
972

Assumed exercise and/or distributions of stock-based awards
—

 
2

 
1

 
1

Diluted(a)
976

 
974

 
976

 
973

 
 
 
 
 
 
 
 
Earnings per average common share:
 
 
 
 
 
 
 
Basic
$
0.53

 
$
0.50

 
$
1.13

 
$
1.43

Diluted
$
0.53

 
$
0.50

 
$
1.13

 
$
1.43

__________
(a)
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 1 million and immaterial for the three and six months ended June 30, 2020, respectively, and immaterial for the three and six months ended June 30, 2019.

See the Combined Notes to Consolidated Financial Statements
10
Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
June 30,
(In millions)
2020
 
2019
Cash flows from operating activities
 
 
 
Net income
$
950

 
$
1,460

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization
2,741

 
2,922

Asset impairments
33

 
9

Gain on sales of assets and businesses
(13
)
 
(33
)
Deferred income taxes and amortization of investment tax credits
33

 
284

Net fair value changes related to derivatives
(194
)
 
107

Net realized and unrealized losses (gains) on NDT funds
196

 
(404
)
Other non-cash operating activities
671

 
277

Changes in assets and liabilities:
 
 
 
Accounts receivable
1,318

 
618

Inventories
(14
)
 
19

Accounts payable and accrued expenses
(798
)
 
(924
)
Option premiums (paid) received, net
(102
)
 
48

Collateral received (posted), net
340

 
(311
)
Income taxes
(114
)
 
151

Pension and non-pension postretirement benefit contributions
(558
)
 
(355
)
Other assets and liabilities
(1,809
)
 
(970
)
Net cash flows provided by operating activities
2,680


2,898

Cash flows from investing activities
 
 
 
Capital expenditures
(3,773
)
 
(3,572
)
Proceeds from NDT fund sales
2,488

 
6,920

Investment in NDT funds
(2,540
)
 
(6,847
)
Collection of DPP
1,102

 
—

Proceeds from sales of assets and businesses
—

 
14

Other investing activities
4

 
26

Net cash flows used in investing activities
(2,719
)

(3,459
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
(751
)
 
470

Proceeds from short-term borrowings with maturities greater than 90 days
500

 
—

Repayments on short-term borrowings with maturities greater than 90 days
—

 
(125
)
Issuance of long-term debt
6,526

 
850

Retirement of long-term debt
(3,894
)
 
(574
)
Dividends paid on common stock
(746
)
 
(704
)
Proceeds from employee stock plans
46

 
75

Other financing activities
(84
)
 
(34
)
Net cash flows provided by (used in) financing activities
1,597


(42
)
Increase (decrease) in cash, cash equivalents and restricted cash
1,558

 
(603
)
Cash, cash equivalents and restricted cash at beginning of period
1,122

 
1,781

Cash, cash equivalents and restricted cash at end of period
$
2,680


$
1,178

 
 
 
 
Supplemental cash flow information
 
 
 
Decrease in capital expenditures not paid
$
(105
)
 
$
(133
)
Increase in DPP
1,754

 
—

Increase in PPE related to ARO update
—

 
301


See the Combined Notes to Consolidated Financial Statements
11
Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
2,129

 
$
587

Restricted cash and cash equivalents
373

 
358

Accounts receivable
 
 
 
Customer accounts receivable
3,075
 
4,835
Customer allowance for credit losses
(261)
 
(243)
Customer accounts receivable, net
2,814

 
4,592

Other accounts receivable
1,549
 
1,631
Other allowance for credit losses
(61)
 
(48)
Other accounts receivable, net
1,488

 
1,583

Mark-to-market derivative assets
573

 
679

Unamortized energy contract assets
43

 
47

Inventories, net
 
 
 
Fossil fuel and emission allowances
273

 
312

Materials and supplies
1,508

 
1,456

Regulatory assets
1,193

 
1,170

Other
2,139

 
1,253

Total current assets
12,533


12,037

Property, plant and equipment (net of accumulated depreciation and amortization of $24,798 and $23,979 as of June 30, 2020 and December 31, 2019, respectively)
81,748

 
80,233

Deferred debits and other assets
 
 
 
Regulatory assets
8,313

 
8,335

Nuclear decommissioning trust funds
12,730

 
13,190

Investments
424

 
464

Goodwill
6,677

 
6,677

Mark-to-market derivative assets
466

 
508

Unamortized energy contract assets
321

 
336

Other
3,101

 
3,197

Total deferred debits and other assets
32,032


32,707

Total assets(a)
$
126,313


$
124,977


See the Combined Notes to Consolidated Financial Statements
12
Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
1,119

 
$
1,370

Long-term debt due within one year
2,514

 
4,710

Accounts payable
3,047

 
3,560

Accrued expenses
1,616

 
1,981

Payables to affiliates
5

 
5

Regulatory liabilities
495

 
406

Mark-to-market derivative liabilities
204

 
247

Unamortized energy contract liabilities
113

 
132

Renewable energy credit obligation
478

 
443

Other
1,474

 
1,331

Total current liabilities
11,065

 
14,185

Long-term debt
36,112

 
31,329

Long-term debt to financing trusts
390

 
390

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
12,720

 
12,351

Asset retirement obligations
11,059

 
10,846

Pension obligations
3,659

 
4,247

Non-pension postretirement benefit obligations
2,121

 
2,076

Spent nuclear fuel obligation
1,206

 
1,199

Regulatory liabilities
9,414

 
9,986

Mark-to-market derivative liabilities
440

 
393

Unamortized energy contract liabilities
292

 
338

Other
2,964

 
3,064

Total deferred credits and other liabilities
43,875

 
44,500

Total liabilities(a)
91,442


90,404

Commitments and contingencies

 

Shareholders’ equity
 
 
 
Common stock (No par value, 2,000 shares authorized, 975 shares and 973 shares outstanding at June 30, 2020 and December 31, 2019, respectively)
19,336

 
19,274

Treasury stock, at cost (2 shares at June 30, 2020 and December 31, 2019)
(123
)
 
(123
)
Retained earnings
16,622

 
16,267

Accumulated other comprehensive loss, net
(3,132
)
 
(3,194
)
Total shareholders’ equity
32,703


32,224

Noncontrolling interests
2,168

 
2,349

Total equity
34,871


34,573

Total liabilities and shareholders’ equity
$
126,313


$
124,977

__________
(a)
Exelon’s consolidated assets include $9,937 million and $9,532 million at June 30, 2020 and December 31, 2019, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,542 million and $3,473 million at June 30, 2020 and December 31, 2019, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 16 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements
13
Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
 
Six Months Ended June 30, 2020
(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, 2019
974,416

 
$
19,274

 
$
(123
)
 
$
16,267

 
$
(3,194
)
 
$
2,349

 
$
34,573

Net income (loss)
—

 
—

 
—

 
582

 
—

 
(206
)
 
376

Long-term incentive plan activity
1,354

 
(4
)
 
—

 
—

 
—

 
—

 
(4
)
Employee stock purchase plan issuances
470

 
31

 
—

 
—

 
—

 
—

 
31

Changes in equity of noncontrolling interests
—

 
—

 
—

 
—

 
—

 
(9
)
 
(9
)
Sale of noncontrolling interests
—

 
2

 
—

 
—

 
—

 
—

 
2

Common stock dividends
($0.38/common share)
—

 
—

 
—

 
(374
)
 
—

 
—

 
(374
)
Other comprehensive income, net of income taxes
—

 
—

 
—

 
—

 
21

 
—

 
21

Balance, March 31, 2020
976,240


$
19,303


$
(123
)

$
16,475


$
(3,173
)

$
2,134


$
34,616

Net income
—

 
—

 
—

 
521

 
—

 
53

 
574

Long-term incentive plan activity
148

 
17

 
—

 
—

 
—

 
—

 
17

Employee stock purchase plan issuances
(51
)
 
15

 
—

 
—

 
—

 
—

 
15

Changes in equity of noncontrolling interests
—

 
—

 
—

 
—

 
—

 
(19
)
 
(19
)
Sale of noncontrolling interests
—

 
1

 
—

 
—

 
—

 
—

 
1

Common stock dividends
($0.38/common share)
—

 
—

 
—

 
(374
)
 
—

 
—

 
(374
)
Other comprehensive income, net of income taxes
—

 
—

 
—

 
—

 
41

 
—

 
41

Balance, June 30, 2020
976,337

 
$
19,336

 
$
(123
)
 
$
16,622

 
$
(3,132
)
 
$
2,168

 
$
34,871






















See the Combined Notes to Consolidated Financial Statements
14
Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
 
Six Months Ended June 30, 2019
(In millions, shares
in thousands)
Issued
Shares
 
Common
Stock
 
Treasury
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 
Total Shareholders'
Equity
Balance, December 31, 2018
970,020

 
$
19,116

 
$
(123
)
 
$
14,766

 
$
(2,995
)
 
$
2,306

 
$
33,070

Net income
—

 
—

 
—

 
907

 
—

 
59

 
966

Long-term incentive plan activity
2,446

 
(3
)
 
—

 
—

 
—

 
—

 
(3
)
Employee stock purchase plan issuances
320

 
51

 
—

 
—

 
—

 
—

 
51

Changes in equity of noncontrolling interests
—

 
—

 
—

 
—

 
—

 
(17
)
 
(17
)
Sale of noncontrolling interests
—

 
7

 
—

 
—

 
—

 
—

 
7

Common stock dividends
($0.36/common share)
—

 
—

 
—

 
(352
)
 
—

 
—

 
(352
)
Other comprehensive loss, net of income taxes
—

 
—

 
—

 
—

 
(17
)
 
(1
)
 
(18
)
Balance, March 31, 2019
972,786

 
$
19,171

 
$
(123
)
 
$
15,321

 
$
(3,012
)
 
$
2,347

 
$
33,704

Net income
—

 
—

 
—

 
484

 
—

 
10

 
494

Long-term incentive plan activity
320

 
14

 
—

 
—

 
—

 
—

 
14

Employee stock purchase plan issuances
311

 
24

 
—

 
—

 
—

 
—

 
24

Changes in equity of noncontrolling interests
—

 
—

 
—

 
—

 
—

 
3

 
3

Common stock dividends
($0.36/common share)
—

 
—

 
—

 
(353
)
 
—

 
—

 
(353
)
Other comprehensive income, net of income taxes
—

 
—

 
—

 
—

 
22

 
(1
)
 
21

Balance, June 30, 2019
973,417

 
$
19,209

 
$
(123
)
 
$
15,452

 
$
(2,990
)
 
$
2,359

 
$
33,907


See the Combined Notes to Consolidated Financial Statements
15
Table of Contents


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)
2020
 
2019
 
2020
 
2019
Operating revenues
 
 
 
 
 
 
 
Operating revenues
$
3,609

 
$
3,958

 
$
8,012

 
$
8,937

Operating revenues from affiliates
271

 
252

 
601

 
569

Total operating revenues
3,880


4,210


8,613


9,506

Operating expenses
 
 
 
 
 
 
 
Purchased power and fuel
1,945

 
2,289

 
4,655

 
5,493

Purchased power and fuel from affiliates
(3
)
 
3

 
(9
)
 
4

Operating and maintenance
1,053

 
1,117

 
2,174

 
2,185

Operating and maintenance from affiliates
136

 
149

 
277

 
299

Depreciation and amortization
300

 
409

 
604

 
814

Taxes other than income taxes
116

 
129

 
246

 
264

Total operating expenses
3,547


4,096


7,947


9,059

Gain on sales of assets and businesses
12

 
33

 
12

 
33

Operating income
345


147


678


480

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(78
)
 
(107
)
 
(179
)
 
(209
)
Interest expense to affiliates
(9
)
 
(9
)
 
(18
)
 
(18
)
Other, net
602

 
171

 
(168
)
 
601

Total other income and (deductions)
515


55


(365
)

374

Income before income taxes
860

 
202

 
313

 
854

Income taxes
329

 
78

 
(59
)
 
301

Equity in losses of unconsolidated affiliates
(2
)
 
(6
)
 
(4
)
 
(13
)
Net income
529


118


368


540

Net income (loss) attributable to noncontrolling interests
53

 
10

 
(153
)
 
68

Net income attributable to membership interest
$
476


$
108


$
521


$
472

Comprehensive income, net of income taxes
 
 
 
 
 
 
 
Net income
$
529

 
$
118

 
$
368

 
$
540

Other comprehensive income (loss), net of income taxes
 
 
 
 
 
 
 
Unrealized loss on cash flow hedges
—

 
(1
)
 
(1
)
 
—

Unrealized loss on investments in unconsolidated affiliates
—

 
(2
)
 
—

 
(4
)
Unrealized gain (loss) on foreign currency translation
2

 
2

 
(6
)
 
4

Other comprehensive income (loss)
2


(1
)

(7
)

—

Comprehensive income
531


117


361


540

Comprehensive income (loss) attributable to noncontrolling interests
53

 
9

 
(153
)
 
66

Comprehensive income attributable to membership interest
$
478

 
$
108

 
$
514

 
$
474


See the Combined Notes to Consolidated Financial Statements
16
Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
June 30,
(In millions)
2020
 
2019
Cash flows from operating activities
 
 
 
Net income
$
368

 
$
540

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization
1,320

 
1,580

Asset impairments
18

 
9

Gain on sales of assets and businesses
(12
)
 
(33
)
Deferred income taxes and amortization of investment tax credits
(54
)
 
151

Net fair value changes related to derivatives
(193
)
 
114

Net realized and unrealized losses (gains) on NDT funds
196

 
(404
)
Other non-cash operating activities
136

 
(50
)
Changes in assets and liabilities:

 

Accounts receivable
1,443

 
472

Receivables from and payables to affiliates, net
68

 
(18
)
Inventories
(34
)
 
32

Accounts payable and accrued expenses
(666
)
 
(507
)
Option premiums (paid) received, net
(102
)
 
48

Collateral posted, net
342

 
(318
)
Income taxes
26

 
321

Pension and non-pension postretirement benefit contributions
(243
)
 
(158
)
Other assets and liabilities
(1,332
)
 
(351
)
Net cash flows provided by operating activities
1,281


1,428

Cash flows from investing activities
 
 
 
Capital expenditures
(930
)
 
(890
)
Proceeds from NDT fund sales
2,488

 
6,920

Investment in NDT funds
(2,540
)
 
(6,847
)
Collection of DPP
1,102

 
—

Proceeds from sales of assets and businesses
—

 
14

Changes in Exelon intercompany money pool
—

 
(179
)
Other investing activities
6

 
8

Net cash flows provided by (used in) investing activities
126


(974
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
(220
)
 
—

Proceeds from short-term borrowings with maturities greater than 90 days
500

 
—

Issuance of long-term debt
2,403

 
40

Retirement of long-term debt
(2,936
)
 
(130
)
Changes in Exelon intercompany money pool
—

 
(100
)
Distributions to member
(937
)
 
(449
)
Other financing activities
(30
)
 
(21
)
Net cash flows used in financing activities
(1,220
)

(660
)
Increase (decrease) in cash, cash equivalents and restricted cash
187

 
(206
)
Cash, cash equivalents and restricted cash at beginning of period
449

 
903

Cash, cash equivalents and restricted cash at end of period
$
636


$
697

 
 
 
 
Supplemental cash flow information
 
 
 
Decrease in capital expenditures not paid
$
(108
)
 
$
(30
)
Increase in DPP
1,754

 
—

Increase in PPE related to ARO update
—

 
301

    

See the Combined Notes to Consolidated Financial Statements
17
Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
483

 
$
303

Restricted cash and cash equivalents
153

 
146

Accounts receivable
 
 
 
Customer accounts receivable
1,117
 
2,973
Customer allowance for credit losses
(33)
 
(80)
Customer accounts receivable, net
1,084

 
2,893

Other accounts receivable
360
 
619
Other accounts receivable, net
360

 
619

Mark-to-market derivative assets
570

 
675

Receivables from affiliates
118

 
190

Unamortized energy contract assets
44

 
47

Inventories, net
 
 
 
Fossil fuel and emission allowances
220

 
236

Materials and supplies
1,075

 
1,026

Renewable energy credits
399

 
336

Other
1,343

 
605

Total current assets
5,849


7,076

Property, plant and equipment (net of accumulated depreciation and amortization of $12,051 and $12,017 as of June 30, 2020 and December 31, 2019, respectively)
23,954

 
24,193

Deferred debits and other assets
 
 
 
Nuclear decommissioning trust funds
12,730

 
13,190

Investments
192

 
235

Goodwill
47

 
47

Mark-to-market derivative assets
466

 
508

Prepaid pension asset
1,613

 
1,438

Unamortized energy contract assets
320

 
336

Deferred income taxes
11

 
12

Other
1,821

 
1,960

Total deferred debits and other assets
17,200


17,726

Total assets(a)
$
47,003


$
48,995


See the Combined Notes to Consolidated Financial Statements
18
Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
LIABILITIES AND EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
600

 
$
320

Long-term debt due within one year
785

 
2,624

Long-term debt to affiliates due within one year
554

 
558

Accounts payable
1,075

 
1,692

Accrued expenses
621

 
786

Payables to affiliates
113

 
117

Mark-to-market derivative liabilities
173

 
215

Unamortized energy contract liabilities
9

 
17

Renewable energy credit obligation
478

 
443

Other
430

 
517

Total current liabilities
4,838

 
7,289

Long-term debt
5,768

 
4,464

Long-term debt to affiliates
326

 
328

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
3,701

 
3,752

Asset retirement obligations
10,819

 
10,603

Non-pension postretirement benefit obligations
868

 
878

Spent nuclear fuel obligation
1,206

 
1,199

Payables to affiliates
2,751

 
3,103

Mark-to-market derivative liabilities
154

 
123

Unamortized energy contract liabilities
10

 
11

Other
1,335

 
1,415

Total deferred credits and other liabilities
20,844

 
21,084

Total liabilities(a)
31,776

 
33,165

Commitments and contingencies

 

Equity
 
 
 
Member’s equity
 
 
 
Membership interest
9,569

 
9,566

Undistributed earnings
3,534

 
3,950

Accumulated other comprehensive loss, net
(39
)
 
(32
)
Total member’s equity
13,064

 
13,484

Noncontrolling interests
2,163

 
2,346

Total equity
15,227

 
15,830

Total liabilities and equity
$
47,003

 
$
48,995

__________
(a)
Generation’s consolidated assets include $9,916 million and $9,512 million at June 30, 2020 and December 31, 2019, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,505 million and $3,429 million at June 30, 2020 and December 31, 2019, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 16 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements
19
Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
 
Six Months Ended June 30, 2020
 
Member’s Equity
 
 
 
 
(In millions)
Membership
Interest
 
Undistributed
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 
Total Equity
Balance, December 31, 2019
$
9,566

 
$
3,950

 
$
(32
)
 
$
2,346

 
$
15,830

Net income (loss)
—

 
45

 
—

 
(206
)
 
(161
)
Changes in equity of noncontrolling interests
—

 
—

 
—

 
(11
)
 
(11
)
Sale of noncontrolling interests
2

 
—

 
—

 
—

 
2

Distributions to member
—

 
(468
)
 
—

 
—

 
(468
)
Other comprehensive loss, net of income taxes
—

 
—

 
(9
)
 
—

 
(9
)
Balance, March 31, 2020
$
9,568


$
3,527


$
(41
)

$
2,129


$
15,183

Net income
—

 
476

 
—

 
53

 
529

Changes in equity of noncontrolling interests
—

 
—

 
—

 
(19
)
 
(19
)
Sale of noncontrolling interests
1

 
—

 
—

 
—

 
1

Distributions to member
—

 
(469
)
 
—

 
—

 
(469
)
Other comprehensive income, net of income taxes
—

 
—

 
2

 
—

 
2

Balance, June 30, 2020
$
9,569

 
$
3,534

 
$
(39
)
 
$
2,163

 
$
15,227


 
Six Months Ended June 30, 2019
 
Member’s Equity
 
 
 
 
(In millions)
Membership
Interest
 
Undistributed
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 
Total Equity
Balance, December 31, 2018
$
9,518

 
$
3,724

 
$
(38
)
 
$
2,304

 
$
15,508

Net income
—

 
363

 
—

 
59

 
422

Changes in equity of noncontrolling interests
—

 
—

 
—

 
(17
)
 
(17
)
Sale of noncontrolling interests
7

 
—

 
—

 
—

 
7

Distributions to member
—

 
(225
)
 
—

 
—

 
(225
)
Other comprehensive income, net of income taxes
—

 
—

 
2

 
(1
)
 
1

Balance, March 31, 2019
$
9,525

 
$
3,862

 
$
(36
)
 
$
2,345

 
$
15,696

Net income
—

 
108

 
—

 
10

 
118

Changes in equity of noncontrolling interests
—

 
—

 
—

 
3

 
3

Distributions to member
—

 
(224
)
 
—

 
—

 
(224
)
Other comprehensive loss, net of income taxes
—

 
—

 
—

 
(1
)
 
(1
)
Balance, June 30, 2019
$
9,525

 
$
3,746

 
$
(36
)
 
$
2,357

 
$
15,592



See the Combined Notes to Consolidated Financial Statements
20
Table of Contents

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)
2020
 
2019
 
2020
 
2019
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
1,431

 
$
1,360

 
$
2,853

 
$
2,792

Revenues from alternative revenue programs
(25
)
 
(14
)
 
(13
)
 
(42
)
Operating revenues from affiliates
11

 
5

 
16

 
9

Total operating revenues
1,417


1,351


2,856


2,759

Operating expenses
 
 
 
 
 
 
 
Purchased power
380

 
316

 
770

 
705

Purchased power from affiliate
84

 
91

 
181

 
187

Operating and maintenance
469

 
245

 
713

 
504

Operating and maintenance from affiliate
67

 
60

 
140

 
122

Depreciation and amortization
274

 
257

 
547

 
508

Taxes other than income taxes
71

 
71

 
146

 
148

Total operating expenses
1,345


1,040


2,497


2,174

Gain on sales of assets
—

 
—

 
—

 
3

Operating income
72


311


359


588

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(95
)
 
(86
)
 
(186
)
 
(171
)
Interest expense to affiliates
(3
)
 
(3
)
 
(6
)
 
(7
)
Other, net
11

 
10

 
22

 
19

Total other income and (deductions)
(87
)

(79
)

(170
)

(159
)
(Loss) income before income taxes
(15
)
 
232

 
189

 
429

Income taxes
46

 
46

 
82

 
85

Net (loss) income
$
(61
)

$
186


$
107


$
344

Comprehensive (loss) income
$
(61
)
 
$
186

 
$
107

 
$
344



21
Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
June 30,
(In millions)
2020
 
2019
Cash flows from operating activities
 
 
 
Net income
$
107

 
$
344

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation, amortization and accretion
547

 
508

Asset impairments
15

 
—

Deferred income taxes and amortization of investment tax credits
129

 
64

Other non-cash operating activities
283

 
87

Changes in assets and liabilities:
 
 
 
Accounts receivable
(92
)
 
56

Receivables from and payables to affiliates, net
(6
)
 
(16
)
Inventories
(7
)
 
(5
)
Accounts payable and accrued expenses
4

 
(121
)
Collateral received (posted), net
(3
)
 
11

Income taxes
(90
)
 
43

Pension and non-pension postretirement benefit contributions
(144
)
 
(68
)
Other assets and liabilities
(245
)
 
(236
)
Net cash flows provided by operating activities
498


667

Cash flows from investing activities
 
 
 
Capital expenditures
(1,029
)
 
(961
)
Other investing activities
(4
)
 
17

Net cash flows used in investing activities
(1,033
)

(944
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
(130
)
 
303

Issuance of long-term debt
1,000

 
400

Retirement of long-term debt
—

 
(300
)
Dividends paid on common stock
(249
)
 
(254
)
Contributions from parent
249

 
124

Other financing activities
(14
)
 
(10
)
Net cash flows provided by financing activities
856


263

Increase (decrease) in cash, cash equivalents and restricted cash
321

 
(14
)
Cash, cash equivalents and restricted cash at beginning of period
403

 
330

Cash, cash equivalents and restricted cash at end of period
$
724


$
316

 
 
 
 
Supplemental cash flow information
 
 
 
Increase (decrease) in capital expenditures not paid
$
18

 
$
(77
)

See the Combined Notes to Consolidated Financial Statements
22
Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
ASSETS
 
 
 
Current assets
 
 
 
   Cash and cash equivalents
$
403

 
$
90

   Restricted cash and cash equivalents
155

 
150

   Accounts receivable
 
 
 
   Customer accounts receivable
706
 
604
   Customer allowance for credit losses
(72)
 
(59)
       Customer accounts receivable, net
634

 
545

   Other accounts receivable
361
 
306
   Other allowance for credit losses
(22)
 
(20)
       Other accounts receivable, net
339

 
286

   Receivables from affiliates
23

 
28

   Inventories, net
166

 
159

   Regulatory assets
271

 
281

   Other
59

 
44

   Total current assets
2,050


1,583

Property, plant and equipment (net of accumulated depreciation and amortization of $5,424 and $5,168 as of June 30, 2020 and December 31, 2019, respectively)
23,717

 
23,107

Deferred debits and other assets
 
 
 
   Regulatory assets
1,610

 
1,480

   Investments
6

 
6

   Goodwill
2,625

 
2,625

   Receivables from affiliates
2,374

 
2,622

   Prepaid pension asset
1,079

 
995

   Other
435

 
347

   Total deferred debits and other assets
8,129


8,075

Total assets
$
33,896


$
32,765


See the Combined Notes to Consolidated Financial Statements
23
Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
   Short-term borrowings
$
—

 
$
130

   Long-term debt due within one year
500

 
500

   Accounts payable
579

 
527

   Accrued expenses
330

 
385

   Payables to affiliates
92

 
103

   Customer deposits
116

 
118

   Regulatory liabilities
175

 
200

   Mark-to-market derivative liabilities
31

 
32

   Deferred Prosecution Agreement payments
200

 
—

   Other
122

 
122

   Total current liabilities
2,145

 
2,117

Long-term debt
8,980

 
7,991

Long-term debt to financing trust
205

 
205

Deferred credits and other liabilities
 
 
 
   Deferred income taxes and unamortized investment tax credits
4,201

 
4,021

   Asset retirement obligations
127

 
128

   Non-pension postretirement benefits obligations
177

 
180

   Regulatory liabilities
6,309

 
6,542

   Mark-to-market derivative liabilities
287

 
269

   Other
681

 
635

   Total deferred credits and other liabilities
11,782

 
11,775

   Total liabilities
23,112

 
22,088

Commitments and contingencies

 

Shareholders’ equity
 
 
 
   Common stock
1,588

 
1,588

   Other paid-in capital
7,821

 
7,572

   Retained deficit unappropriated
(1,700
)
 
(1,639
)
   Retained earnings appropriated
3,075

 
3,156

   Total shareholders’ equity
10,784

 
10,677

Total liabilities and shareholders’ equity
$
33,896

 
$
32,765


See the Combined Notes to Consolidated Financial Statements
24
Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
 
Six Months Ended June 30, 2020
(In millions)
Common
Stock
 
Other
Paid-In
Capital
 
Retained Deficit
Unappropriated
 
Retained
Earnings
Appropriated
 
Total
Shareholders’
Equity
Balance, December 31, 2019
$
1,588

 
$
7,572

 
$
(1,639
)
 
$
3,156

 
$
10,677

Net income
—

 
—

 
168

 
—

 
168

Appropriation of retained earnings for future dividends
—

 
—

 
(168
)
 
168

 
—

Common stock dividends
—

 
—

 
—

 
(125
)
 
(125
)
Contributions from parent
—

 
125

 
—

 
—

 
125

Balance, March 31, 2020
$
1,588

 
$
7,697

 
$
(1,639
)
 
$
3,199

 
$
10,845

Net loss
—

 
—

 
(61
)
 
—

 
(61
)
Common stock dividends
—

 
—

 
—

 
(124
)
 
(124
)
Contributions from parent
—

 
124

 
—

 
—

 
124

Balance, June 30, 2020
$
1,588

 
$
7,821

 
$
(1,700
)
 
$
3,075

 
$
10,784

 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 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

Net income
—

 
—

 
186

 
—

 
186

Appropriation of retained earnings for future dividends
—

 
—

 
(186
)
 
186

 
—

Common stock dividends
—

 
—

 
—

 
(127
)
 
(127
)
Contributions from parent
—

 
61

 
—

 
—

 
61

Balance, June 30, 2019
$
1,588

 
$
7,446

 
$
(1,639
)
 
$
3,065

 
$
10,460


See the Combined Notes to Consolidated Financial Statements
25
Table of Contents


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)
2020
 
2019
 
2020
 
2019
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
580

 
$
567

 
$
1,180

 
$
1,188

Natural gas operating revenues
95

 
89

 
304

 
369

Revenues from alternative revenue programs
4

 
(3
)
 
5

 
(6
)
Operating revenues from affiliates
2

 
2

 
4

 
3

Total operating revenues
681


655


1,493


1,554

Operating expenses
 
 
 
 
 
 
 
Purchased power
142

 
124

 
306

 
275

Purchased fuel
34

 
32

 
117

 
166

Purchased power from affiliate
40

 
35

 
76

 
79

Operating and maintenance
235

 
162

 
414

 
349

Operating and maintenance from affiliates
40

 
37

 
78

 
75

Depreciation and amortization
88

 
83

 
173

 
164

Taxes other than income taxes
39

 
37

 
78

 
79

Total operating expenses
618


510


1,242


1,187

Operating income
63


145


251


367

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(33
)
 
(30
)
 
(65
)
 
(61
)
Interest expense to affiliates
(3
)
 
(3
)
 
(6
)
 
(6
)
Other, net
5

 
3

 
7

 
7

Total other income and (deductions)
(31
)

(30
)

(64
)

(60
)
Income before income taxes
32

 
115

 
187


307

Income taxes
(7
)
 
13

 
9

 
37

Net income
$
39


$
102


$
178


$
270

Comprehensive income
$
39

 
$
102

 
$
178

 
$
270


See the Combined Notes to Consolidated Financial Statements
26
Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
June 30,
(In millions)
2020
 
2019
Cash flows from operating activities
 
 
 
Net income
$
178

 
$
270

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
173

 
164

Deferred income taxes and amortization of investment tax credits
6

 
8

Other non-cash operating activities
25

 
15

Changes in assets and liabilities:
 
 
 
Accounts receivable
22

 
39

Receivables from and payables to affiliates, net
3

 
(4
)
Inventories
10

 
12

Accounts payable and accrued expenses
27

 
(31
)
Income taxes
15

 
(11
)
Pension and non-pension postretirement benefit contributions
(18
)
 
(27
)
Other assets and liabilities
(48
)
 
(117
)
Net cash flows provided by operating activities
393


318

Cash flows from investing activities
 
 
 
Capital expenditures
(512
)
 
(447
)
Changes in Exelon intercompany money pool
68

 
—

Other investing activities
3

 
4

Net cash flows used in investing activities
(441
)

(443
)
Cash flows from financing activities
 
 
 
Issuance of long-term debt
350

 
—

Changes in Exelon intercompany money pool
—

 
52

Dividends paid on common stock
(170
)
 
(180
)
Contributions from parent
231

 
145

Other financing activities
(3
)
 
(1
)
Net cash flows provided by financing activities
408


16

Increase (decrease) in cash, cash equivalents and restricted cash
360

 
(109
)
Cash, cash equivalents and restricted cash at beginning of period
27

 
135

Cash, cash equivalents and restricted cash at end of period
$
387


$
26

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

 
$
33


See the Combined Notes to Consolidated Financial Statements
27
Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
380

 
$
21

Restricted cash and cash equivalents
7

 
6

Accounts receivable
 
 
 
Customer accounts receivable
379
 
412
Customer allowance for credit losses
(71)
 
(55)
Customer accounts receivable, net
308

 
357

Other accounts receivable
128
 
145
Other allowance for credit losses
(7)
 
(7)
Other accounts receivable, net
121

 
138

Receivables from affiliates
—

 
1

Receivable from Exelon intercompany money pool
—

 
68

Inventories, net
 
 
 
Fossil fuel
26

 
36

Materials and supplies
35

 
35

Prepaid utility taxes
76

 
—

Regulatory assets
46

 
41

Other
21

 
19

Total current assets
1,020


722

Property, plant and equipment (net of accumulated depreciation and amortization of $3,782 and $3,718 as of June 30, 2020 and December 31, 2019, respectively)
9,688

 
9,292

Deferred debits and other assets
 
 
 
Regulatory assets
604

 
554

Investments
27

 
27

Receivables from affiliates
376

 
480

Prepaid pension asset
379

 
365

Other
26

 
29

Total deferred debits and other assets
1,412


1,455

Total assets
$
12,120


$
11,469


See the Combined Notes to Consolidated Financial Statements
28
Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
463

 
$
387

Accrued expenses
92

 
101

Payables to affiliates
57

 
55

Customer deposits
67

 
69

Regulatory liabilities
116

 
91

Other
29

 
19

Total current liabilities
824

 
722

Long-term debt
3,752

 
3,405

Long-term debt to financing trusts
184

 
184

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
2,139

 
2,080

Asset retirement obligations
26

 
28

Non-pension postretirement benefits obligations
287

 
288

Regulatory liabilities
404

 
510

Other
86

 
74

Total deferred credits and other liabilities
2,942

 
2,980

Total liabilities
7,702

 
7,291

Commitments and contingencies

 

Shareholder’s equity
 
 
 
Common stock
2,997

 
2,766

Retained earnings
1,421

 
1,412

Total shareholder’s equity
4,418

 
4,178

Total liabilities and shareholder's equity
$
12,120

 
$
11,469


See the Combined Notes to Consolidated Financial Statements
29
Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
 
Six months ended June 30, 2020
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholder's
Equity
Balance, December 31, 2019
$
2,766

 
$
1,412

 
$
4,178

Net income
—

 
140

 
140

Common stock dividends
—

 
(85
)
 
(85
)
Contributions from parent
231

 
—

 
231

Balance, March 31, 2020
$
2,997

 
$
1,467

 
$
4,464

Net income
—

 
39

 
39

Common stock dividends
—

 
(85
)
 
(85
)
Balance, June 30, 2020
$
2,997

 
$
1,421

 
$
4,418

 
 
 
 
 
 
 
Six months ended June 30, 2019
(In millions)
Common
Stock
 
Retained
Earnings
 
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 parent
145

 
—

 
145

Balance, March 31, 2019
$
2,723

 
$
1,320

 
$
4,043

Net income
—

 
102

 
102

Common stock dividends
—

 
(90
)
 
(90
)
Balance, June 30, 2019
$
2,723

 
$
1,332

 
$
4,055


See the Combined Notes to Consolidated Financial Statements
30
Table of Contents


BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(In millions)
2020
 
2019
 
2020
 
2019
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
530

 
$
540

 
$
1,125

 
$
1,191

Natural gas operating revenues
119

 
97

 
419

 
405

Revenues from alternative revenue programs
(37
)
 
6

 
—

 
17

Operating revenues from affiliates
4

 
6

 
10

 
12

Total operating revenues
616


649


1,554


1,625

Operating expenses
 
 
 
 
 
 
 
Purchased power
107

 
131

 
221

 
322

Purchased fuel
18

 
21

 
95

 
116

Purchased power and fuel from affiliate
69

 
56

 
167

 
132

Operating and maintenance
146

 
142

 
293

 
294

Operating and maintenance from affiliates
41

 
40

 
83

 
78

Depreciation and amortization
129

 
117

 
272

 
252

Taxes other than income taxes
63

 
62

 
132

 
131

Total operating expenses
573


569


1,263


1,325

Operating income
43


80


291


300

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(32
)
 
(29
)
 
(64
)
 
(58
)
Other, net
6

 
5

 
10

 
11

Total other income and (deductions)
(26
)

(24
)

(54
)

(47
)
Income before income taxes
17

 
56

 
237


253

Income taxes
(22
)
 
11

 
18

 
47

Net income
$
39


$
45


$
219


$
206

Comprehensive income
$
39

 
$
45

 
$
219

 
$
206


See the Combined Notes to Consolidated Financial Statements
31
Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
June 30,
(In millions)
2020
 
2019
Cash flows from operating activities
 
 
 
Net income
$
219

 
$
206

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
272

 
252

Deferred income taxes and amortization of investment tax credits
22

 
47

Other non-cash operating activities
50

 
41

Changes in assets and liabilities:
 
 
 
Accounts receivable
19

 
85

Receivables from and payables to affiliates, net
(26
)
 
(14
)
Inventories
10

 
5

Accounts payable and accrued expenses
(15
)
 
(73
)
Collateral posted, net
—

 
(5
)
Income taxes
26

 
(29
)
Pension and non-pension postretirement benefit contributions
(68
)
 
(42
)
Other assets and liabilities
(5
)
 
(21
)
Net cash flows provided by operating activities
504


452

Cash flows from investing activities
 
 
 
Capital expenditures
(548
)
 
(542
)
Other investing activities
(4
)
 
4

Net cash flows used in investing activities
(552
)

(538
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
(76
)
 
194

Issuance of long-term debt
400

 
—

Dividends paid on common stock
(123
)
 
(112
)
Contributions from parent
26

 
—

Other financing activities
(8
)
 
—

Net cash flows provided by financing activities
219


82

Increase (decrease) in cash, cash equivalents and restricted cash
171

 
(4
)
Cash, cash equivalents and restricted cash at beginning of period
25

 
13

Cash, cash equivalents and restricted cash at end of period
$
196


$
9

 
 
 
 
Supplemental cash flow information
 
 
 
(Decrease) increase in capital expenditures not paid
$
(14
)
 
$
24


See the Combined Notes to Consolidated Financial Statements
32
Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
195

 
$
24

Restricted cash and cash equivalents
1

 
1

Accounts receivable
 
 
 
Customer accounts receivable
318
 
329
Customer allowance for credit losses
(23)
 
(12)
    Customer accounts receivable, net
295

 
317

Other accounts receivable
121
 
152
Other allowance for credit losses
(6)
 
(5)
     Other accounts receivable, net
115

 
147

Receivables from affiliates
—

 
1

Inventories, net
 
 
 
Fossil fuel
22

 
30

Materials and supplies
44

 
46

Prepaid utility taxes
—

 
78

Regulatory assets
177

 
183

Other
6

 
6

Total current assets
855


833

Property, plant and equipment (net of accumulated depreciation and amortization of $3,906 and $3,834 as of June 30, 2020 and December 31, 2019, respectively)
9,332

 
8,990

Deferred debits and other assets
 
 
 
Regulatory assets
464

 
454

Investments
10

 
7

Prepaid pension asset
295

 
264

Other
71

 
86

Total deferred debits and other assets
840


811

Total assets
$
11,027


$
10,634


See the Combined Notes to Consolidated Financial Statements
33
Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
—

 
$
76

Accounts payable
244

 
243

Accrued expenses
120

 
152

Payables to affiliates
41

 
66

Customer deposits
118

 
120

Regulatory liabilities
44

 
33

Other
63

 
63

Total current liabilities
630

 
753

Long-term debt
3,663

 
3,270

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
1,480

 
1,396

Asset retirement obligations
22

 
22

Non-pension postretirement benefits obligations
193

 
199

Regulatory liabilities
1,131

 
1,195

Other
103

 
116

Total deferred credits and other liabilities
2,929

 
2,928

Total liabilities
7,222

 
6,951

Commitments and contingencies

 

Shareholder's equity
 
 
 
Common stock
1,933

 
1,907

Retained earnings
1,872

 
1,776

Total shareholder's equity
3,805

 
3,683

Total liabilities and shareholder's equity
$
11,027

 
$
10,634




See the Combined Notes to Consolidated Financial Statements
34
Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
 
Six Months Ended June 30, 2020
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholder's
Equity
Balance, December 31, 2019
$
1,907

 
$
1,776

 
$
3,683

Net income
—

 
181

 
181

Common stock dividends
—

 
(62
)
 
(62
)
Balance, March 31, 2020
$
1,907

 
$
1,895

 
$
3,802

Net income
—

 
39

 
39

Common stock dividends
—

 
(62
)
 
(62
)
Contributions from parent
26

 
—

 
26

Balance, June 30, 2020
$
1,933


$
1,872

 
$
3,805

 
 
 
 
 
 
 
Six Months Ended June 30, 2019
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholder's
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

Net income
—

 
45

 
45

Common stock dividends
—

 
(55
)
 
(55
)
Balance, June 30, 2019
$
1,714

 
$
1,734

 
$
3,448


See the Combined Notes to Consolidated Financial Statements
35
Table of Contents


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)
2020
 
2019
 
2020
 
2019
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
1,047

 
$
1,067

 
$
2,133

 
$
2,205

Natural gas operating revenues
30

 
24

 
94

 
95

Revenues from alternative revenue programs
(64
)
 
(3
)
 
(47
)
 
12

Operating revenues from affiliates
3

 
3

 
7

 
7

Total operating revenues
1,016

 
1,091

 
2,187

 
2,319

Operating expenses
 
 
 
 
 
 
 
Purchased power
286

 
303

 
586

 
658

Purchased fuel
11

 
9

 
42

 
43

Purchased power from affiliates
78

 
70

 
182

 
171

Operating and maintenance
245

 
213

 
464

 
452

Operating and maintenance from affiliates
36

 
35

 
74

 
68

Depreciation and amortization
191

 
188

 
385

 
369

Taxes other than income taxes
109

 
108

 
222

 
220

Total operating expenses
956

 
926

 
1,955

 
1,981

Gain on sales of assets
—

 
—

 
2

 
—

Operating income
60

 
165


234

 
338

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(67
)
 
(67
)
 
(134
)
 
(131
)
Other, net
14

 
14

 
26

 
27

Total other income and (deductions)
(53
)
 
(53
)
 
(108
)
 
(104
)
Income before income taxes
7

 
112

 
126

 
234

Income taxes
(87
)
 
6

 
(76
)
 
11

Net income
$
94

 
$
106

 
$
202

 
$
223

Comprehensive income
$
94

 
$
106

 
$
202

 
$
223


See the Combined Notes to Consolidated Financial Statements
36
Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
June 30,
(In millions)
2020
 
2019
Cash flows from operating activities
 
 

Net income
$
202

 
$
223

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
385

 
369

Deferred income taxes and amortization of investment tax credits
(74
)
 
2

Other non-cash operating activities
107

 
54

Changes in assets and liabilities:
 
 
 
Accounts receivable
(64
)
 
(34
)
Receivables from and payables to affiliates, net
(22
)
 
(8
)
Inventories
6

 
(25
)
Accounts payable and accrued expenses
14

 
(25
)
Income taxes
(30
)
 
(12
)
Pension and non-pension postretirement benefit contributions
(31
)
 
(11
)
Other assets and liabilities
(146
)
 
(114
)
Net cash flows provided by operating activities
347

 
419

Cash flows from investing activities
 
 
 
Capital expenditures
(686
)
 
(698
)
Other investing activities
2

 
2

Net cash flows used in investing activities
(684
)

(696
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
(189
)
 
(27
)
Repayments of short-term borrowings with maturities greater than 90 days
—

 
(125
)
Issuance of long-term debt
373

 
410

Retirement of long-term debt
(35
)
 
(125
)
Changes in Exelon intercompany money pool
10

 
3

Distributions to member
(268
)
 
(216
)
Contributions from member
359

 
283

Other financing activities
(8
)
 
(4
)
Net cash flows provided by financing activities
242

 
199

Decrease in cash, cash equivalents and restricted cash
(95
)
 
(78
)
Cash, cash equivalents and restricted cash at beginning of period
181

 
186

Cash, cash equivalents and restricted cash at end of period
$
86

 
$
108

 
 
 
 
Supplemental cash flow information
 
 
 
Decrease in capital expenditures not paid
$
(24
)
 
$
(74
)

See the Combined Notes to Consolidated Financial Statements
37
Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
39

 
$
131

Restricted cash and cash equivalents
36

 
36

Accounts receivable
 
 
 
Customer accounts receivable
554
 
516
Customer allowance for credit losses
(62)
 
(37)
Customer accounts receivable, net
492

 
479

Other accounts receivable
234
 
190
Other allowance for credit losses
(26)
 
(16)
Other accounts receivable, net
208

 
174

Receivables from affiliates
1

 
1

Inventories, net
 
 
 
Fossil fuel
5

 
8

Materials and supplies
187

 
190

Regulatory assets
449

 
412

Other
75

 
49

Total current assets
1,492


1,480

Property, plant and equipment (net of accumulated depreciation and amortization of $1,591 and $1,213 as of June 30, 2020 and December 31, 2019, respectively)
14,692

 
14,296

Deferred debits and other assets
 
 
 
Regulatory assets
1,962

 
2,061

Investments
135

 
135

Goodwill
4,005

 
4,005

Prepaid pension asset
396

 
406

Deferred income taxes
13

 
13

Other
309

 
323

Total deferred debits and other assets
6,820


6,943

Total assets(a)
$
23,004


$
22,719


See the Combined Notes to Consolidated Financial Statements
38
Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
LIABILITIES AND MEMBER'S EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
19

 
$
208

Long-term debt due within one year
350

 
103

Accounts payable
486

 
462

Accrued expenses
238

 
296

Payables to affiliates
76

 
98

Borrowings from Exelon intercompany money pool
22

 
12

Customer deposits
115

 
117

Regulatory liabilities
148

 
70

Unamortized energy contract liabilities
103

 
115

Other
128

 
131

Total current liabilities
1,685

 
1,612

Long-term debt
6,540

 
6,460

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
2,350

 
2,278

Asset retirement obligations
57

 
57

Non-pension postretirement benefit obligations
87

 
93

Regulatory liabilities
1,553

 
1,707

Unamortized energy contract liabilities
282

 
327

Other
549

 
577

Total deferred credits and other liabilities
4,878

 
5,039

Total liabilities(a)
13,103

 
13,111

Commitments and contingencies

 

Member's equity
 
 
 
Membership interest
9,977

 
9,618

Undistributed losses
(76
)
 
(10
)
Total member's equity
9,901


9,608

Total liabilities and member's equity
$
23,004


$
22,719

__________
(a)
PHI’s consolidated total assets include $21 million and $20 million at June 30, 2020 and December 31, 2019, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $37 million and $44 million at June 30, 2020 and December 31, 2019, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 16 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements
39
Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
 
Six Months Ended June 30, 2020
(In millions)
Membership Interest
 
Undistributed Earnings (Losses)
 
Member's Equity
Balance, December 31, 2019
$
9,618

 
$
(10
)
 
$
9,608

Net income
—

 
108

 
108

Distributions to member
—

 
(134
)
 
(134
)
Contributions from member
144

 
—

 
144

Balance, March 31, 2020
$
9,762

 
$
(36
)
 
$
9,726

Net income
—

 
94

 
94

Distributions to member
—

 
(134
)
 
(134
)
Contributions from member
215

 
—

 
215

Balance, June 30, 2020
$
9,977

 
$
(76
)
 
$
9,901

 
Six Months Ended June 30, 2019
(In millions)
Membership Interest
 
Undistributed Earnings (Losses)
 
Member's Equity
Balance, December 31, 2018
$
9,220

 
$
62

 
$
9,282

Net income
—

 
117

 
117

Distributions to member
—

 
(128
)
 
(128
)
Contributions from member
19

 
—

 
19

Balance, March 31, 2019
$
9,239

 
$
51

 
$
9,290

Net income
—

 
106

 
106

Distributions to member
—

 
(88
)
 
(88
)
Contributions from member
264

 
—

 
264

Balance, June 30, 2019
$
9,503

 
$
69

 
$
9,572


See the Combined Notes to Consolidated Financial Statements
40
Table of Contents


POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
(In millions)
2020

2019
 
2020
 
2019
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
506

 
$
531

 
$
1,034

 
$
1,090

Revenues from alternative revenue programs
(13
)
 
(1
)
 
2

 
13

Operating revenues from affiliates
1

 
1

 
3

 
3

Total operating revenues
494

 
531

 
1,039

 
1,106

Operating expenses
 
 
 
 
 
 
 
Purchased power
78

 
92

 
164

 
209

Purchased power from affiliate
60

 
52

 
139

 
122

Operating and maintenance
67

 
59

 
128

 
123

Operating and maintenance from affiliates
52

 
52

 
103

 
107

Depreciation and amortization
92

 
93

 
186

 
186

Taxes other than income taxes
87

 
90

 
179

 
182

Total operating expenses
436

 
438

 
899

 
929

Operating income
58

 
93

 
140

 
177

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(34
)
 
(34
)
 
(68
)
 
(68
)
Other, net
9

 
7

 
18

 
14

Total other income and (deductions)
(25
)
 
(27
)
 
(50
)
 
(54
)
Income before income taxes
33

 
66

 
90

 
123

Income taxes
(24
)
 
2

 
(19
)
 
4

Net income
$
57

 
$
64

 
$
109

 
$
119

Comprehensive income
$
57

 
$
64

 
$
109

 
$
119


See the Combined Notes to Consolidated Financial Statements
41
Table of Contents

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
June 30,
(In millions)
2020
 
2019
Cash flows from operating activities
 
 
 
Net income
$
109

 
$
119

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
186

 
186

Deferred income taxes and amortization of investment tax credits
(22
)
 
10

Other non-cash operating activities
11

 
8

Changes in assets and liabilities:
 
 
 
Accounts receivable
(45
)
 
(36
)
Receivables from and payables to affiliates, net
(22
)
 
4

Inventories
3

 
(20
)
Accounts payable and accrued expenses
11

 
(25
)
Income taxes
(18
)
 
(23
)
Pension and non-pension postretirement benefit contributions
(6
)
 
(6
)
Other assets and liabilities
(52
)
 
(40
)
Net cash flows provided by operating activities
155

 
177

Cash flows from investing activities
 
 
 
Capital expenditures
(324
)
 
(298
)
Changes in PHI intercompany money pool
—

 
(38
)
Other investing activities
(3
)
 
1

Net cash flows used in investing activities
(327
)
 
(335
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
(68
)
 
(40
)
Issuance of long-term debt
150

 
260

Retirement of long-term debt
(1
)
 
(117
)
Changes in PHI intercompany money pool
50

 
—

Dividends paid on common stock
(101
)
 
(72
)
Contributions from parent
137

 
129

Other financing activities
(6
)
 
(3
)
Net cash flows provided by financing activities
161

 
157

Decrease in cash, cash equivalents and restricted cash
(11
)
 
(1
)
Cash, cash equivalents and restricted cash at beginning of period
63

 
53

Cash, cash equivalents and restricted cash at end of period
$
52

 
$
52

 
 
 
 
Supplemental cash flow information
 
 
 
Decrease in capital expenditures not paid
$
(28
)
 
$
(18
)

See the Combined Notes to Consolidated Financial Statements
42
Table of Contents

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020

December 31, 2019
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
19

 
$
30

Restricted cash and cash equivalents
33

 
33

Accounts receivable
 
 
 
Customer accounts receivable
272
 
244
Customer allowance for credit losses
(24)
 
(13)
Customer accounts receivable, net
248

 
231

Other accounts receivable
121
 
98
Other allowance for credit losses
(11)
 
(7)
Other accounts receivable, net
110

 
91

Receivables from affiliates
2

 
—

Inventories, net
109

 
112

Regulatory assets
215

 
188

Other
11

 
11

Total current assets
747


696

Property, plant and equipment (net of accumulated depreciation and amortization of $3,604 and $3,517 as of June 30, 2020 and December 31, 2019, respectively)
7,102

 
6,909

Deferred debits and other assets
 
 
 
Regulatory assets
556

 
584

Investments
111

 
110

Prepaid pension asset
290

 
296

Other
63

 
66

Total deferred debits and other assets
1,020


1,056

Total assets
$
8,869


$
8,661


See the Combined Notes to Consolidated Financial Statements
43
Table of Contents

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
14

 
$
82

Long-term debt due within one year
3

 
2

Accounts payable
195

 
195

Accrued expenses
123

 
156

Payables to affiliates
46

 
66

Borrowings from PHI intercompany money pool
50

 
—

Customer deposits
57

 
57

Regulatory liabilities
48

 
8

Merger related obligation
39

 
39

Current portion of DC PLUG obligation
30

 
30

Other
16

 
22

Total current liabilities
621


657

Long-term debt
3,010

 
2,862

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
1,168

 
1,131

Asset retirement obligations
41

 
41

Non-pension postretirement benefit obligations
15

 
20

Regulatory liabilities
686

 
746

Other
276

 
297

Total deferred credits and other liabilities
2,186


2,235

Total liabilities
5,817


5,754

Commitments and contingencies

 

Shareholder's equity
 
 
 
Common stock
1,933

 
1,796

Retained earnings
1,119

 
1,111

Total shareholder's equity
3,052

 
2,907

Total liabilities and shareholder's equity
$
8,869

 
$
8,661


See the Combined Notes to Consolidated Financial Statements
44
Table of Contents

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
 
Six Months Ended June 30, 2020
(In millions)
Common Stock
 
Retained Earnings
 
Total Shareholder's Equity
Balance, December 31, 2019
$
1,796

 
$
1,111

 
$
2,907

Net income
—

 
52

 
52

Common stock dividends
—

 
(28
)
 
(28
)
Contributions from parent
137

 
—

 
137

Balance, March 31, 2020
$
1,933

 
$
1,135

 
$
3,068

Net income
—

 
57

 
57

Common stock dividends
—

 
(73
)
 
(73
)
Balance, June 30, 2020
$
1,933

 
$
1,119

 
$
3,052

 
Six Months Ended June 30, 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 parent
14

 
—

 
14

Balance, March 31, 2019
$
1,650

 
$
1,135

 
$
2,785

Net income
—

 
64

 
64

Common stock dividends
—

 
(48
)
 
(48
)
Contributions from parent
115

 
—

 
115

Balance, June 30, 2019
$
1,765

 
$
1,151

 
$
2,916



See the Combined Notes to Consolidated Financial Statements
45
Table of Contents


DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 
Three Months Ended
June 30,

Six Months Ended
June 30,
(In millions)
2020

2019

2020

2019
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
260

 
$
261

 
$
543

 
$
568

Natural gas operating revenues
30

 
24

 
94

 
95

Revenues from alternative revenue programs
(25
)
 
—

 
(24
)
 
1

Operating revenues from affiliates
2

 
2

 
4

 
3

Total operating revenues
267


287


617


667

Operating expenses
 
 
 
 
 
 
 
Purchased power
80

 
86

 
169

 
193

Purchased fuel
11

 
9

 
42

 
43

Purchased power from affiliates
16

 
12

 
38

 
35

Operating and maintenance
54

 
39

 
97

 
84

Operating and maintenance from affiliates
38

 
38

 
75

 
76

Depreciation and amortization
47

 
45

 
94

 
91

Taxes other than income taxes
17

 
14

 
32

 
28

Total operating expenses
263


243


547


550

Operating income
4


44


70


117

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(15
)
 
(15
)
 
(31
)
 
(30
)
Other, net
2

 
5

 
5

 
7

Total other income and (deductions)
(13
)

(10
)

(26
)

(23
)
(Loss) income before income taxes
(9
)
 
34

 
44

 
94

Income taxes
(28
)
 
4

 
(20
)
 
11

Net income
$
19


$
30


$
64


$
83

Comprehensive income
$
19

 
$
30

 
$
64

 
$
83


See the Combined Notes to Consolidated Financial Statements
46
Table of Contents

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
June 30,
(In millions)
2020

2019
Cash flows from operating activities
 
 
 
Net income
$
64

 
$
83

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
94

 
91

Deferred income taxes and amortization of investment tax credits
(19
)
 
(5
)
Other non-cash operating activities
40

 
11

Changes in assets and liabilities:
 
 
 
Accounts receivable
6

 
15

Receivables from and payables to affiliates, net
(2
)
 
(11
)
Inventories
—

 
(3
)
Accounts payable and accrued expenses
3

 
6

Income taxes
(12
)
 
11

Pension and non-pension postretirement benefit contributions
—

 
(1
)
Other assets and liabilities
(21
)
 
(26
)
Net cash flows provided by operating activities
153


171

Cash flows from investing activities
 
 
 
Capital expenditures
(184
)
 
(160
)
Changes in PHI intercompany money pool
(55
)
 
—

Other investing activities
(3
)
 
1

Net cash flows used in investing activities
(242
)

(159
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
(56
)
 
—

Issuance of long-term debt
100

 
—

Retirement of long-term debt
(1
)
 
—

Changes in PHI intercompany money pool
—

 
38

Dividends paid on common stock
(66
)
 
(70
)
Contributions from parent
106

 
—

Other financing activities
(1
)
 
—

Net cash flows provided by (used in) financing activities
82


(32
)
Decrease in cash, cash equivalents and restricted cash
(7
)
 
(20
)
Cash, cash equivalents and restricted cash at beginning of period
13

 
24

Cash, cash equivalents and restricted cash at end of period
$
6


$
4

 
 
 
 
Supplemental cash flow information
 
 
 
Decrease in capital expenditures not paid
$
(4
)
 
$
(17
)

See the Combined Notes to Consolidated Financial Statements
47
Table of Contents

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
6

 
$
13

Accounts receivable
 
 
 
Customer accounts receivable
145
 
152
Customer allowance for credit losses
(18)
 
(11)
Customer accounts receivable, net
127

 
141

Other accounts receivable
48
 
42
Other allowance for credit losses
(7)
 
(4)
Other accounts receivable, net
41

 
38

Receivables from affiliates
1

 
—

Receivable from PHI intercompany pool
55

 
—

Inventories, net
 
 
 
Fossil fuel
5

 
8

Materials and supplies
47

 
44

Prepaid utility taxes
2

 
18

Regulatory assets
55

 
52

Renewable energy credits
21

 
9

Other
3

 
2

Total current assets
363


325

Property, plant and equipment (net of accumulated depreciation and amortization of $1,476 and $1,425 as of June 30, 2020 and December 31, 2019, respectively)
4,143

 
4,035

Deferred debits and other assets
 
 
 
Regulatory assets
222

 
222

Goodwill
8

 
8

Prepaid pension asset
166

 
171

Other
64

 
69

Total deferred debits and other assets
460


470

Total assets
$
4,966


$
4,830


See the Combined Notes to Consolidated Financial Statements
48
Table of Contents

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
—

 
$
56

Long-term debt due within one year
81

 
80

Accounts payable
113

 
112

Accrued expenses
34

 
46

Payables to affiliates
27

 
32

Customer deposits
35

 
36

Regulatory liabilities
60

 
37

Other
17

 
15

Total current liabilities
367

 
414

Long-term debt
1,594

 
1,487

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
680

 
655

Non-pension postretirement benefits obligations
15

 
16

Regulatory liabilities
526

 
574

Other
100

 
104

Total deferred credits and other liabilities
1,321


1,349

Total liabilities
3,282


3,250

Commitments and contingencies

 

Shareholder's equity
 
 
 
Common stock
1,083

 
977

Retained earnings
601

 
603

Total shareholder's equity
1,684


1,580

Total liabilities and shareholder's equity
$
4,966


$
4,830


See the Combined Notes to Consolidated Financial Statements
49
Table of Contents

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
 
Six Months Ended June 30, 2020
(In millions)
Common Stock
 
Retained Earnings
 
Total Shareholder's Equity
Balance, December 31, 2019
$
977

 
$
603

 
$
1,580

Net income
—

 
45

 
45

Common stock dividends
—

 
(52
)
 
(52
)
Contributions from parent
6

 
—

 
6

Balance, March 31, 2020
983

 
596

 
1,579

Net income
—

 
19

 
19

Common stock dividends
—

 
(14
)
 
(14
)
Contributions from parent
100

 
—

 
100

Balance, June 30, 2020
$
1,083

 
$
601

 
$
1,684


 
Six Months Ended June 30, 2019
(In millions)
Common Stock
 
Retained Earnings
 
Total Shareholder's Equity
Balance, December 31, 2018
$
914

 
$
595

 
$
1,509

Net income
—

 
53

 
53

Common stock dividends
—

 
(41
)
 
(41
)
Balance, March 31, 2019
914

 
607

 
1,521

Net income
—

 
30

 
30

Common stock dividends
—

 
(29
)
 
(29
)
Balance, June 30, 2019
$
914

 
$
608

 
$
1,522



See the Combined Notes to Consolidated Financial Statements
50
Table of Contents


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)
2020
 
2019
 
2020
 
2019
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
281

 
$
275

 
$
556

 
$
547

Revenues from alternative revenue programs
(26
)
 
(2
)
 
(25
)
 
(1
)
Operating revenues from affiliates
1

 
1

 
1

 
1

Total operating revenues
256

 
274

 
532

 
547

Operating expenses
 
 
 
 
 
 
 
Purchased power
128

 
125

 
254

 
257

Purchased power from affiliate
2

 
6

 
5

 
13

Operating and maintenance
48

 
41

 
94

 
88

Operating and maintenance from affiliates
34

 
33

 
66

 
67

Depreciation and amortization
44

 
40

 
86

 
71

Taxes other than income taxes
2

 
1

 
4

 
2

Total operating expenses
258

 
246

 
509

 
498

Gain on sale of assets
—

 
—

 
2

 
—

Operating (loss) income
(2
)

28

 
25

 
49

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(15
)
 
(15
)
 
(29
)
 
(28
)
Other, net
2

 
1

 
3

 
4

Total other income and (deductions)
(13
)
 
(14
)
 
(26
)
 
(24
)
(Loss) income before income taxes
(15
)
 
14

 
(1
)
 
25

Income taxes
(33
)
 
—

 
(32
)
 
1

Net income
$
18


$
14

 
$
31

 
$
24

Comprehensive income
$
18

 
$
14

 
$
31

 
$
24


See the Combined Notes to Consolidated Financial Statements
51
Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Six Months Ended
June 30,
(In millions)
2020

2019
Cash flows from operating activities
 
 
 
Net income
$
31

 
$
24

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
86

 
71

Deferred income taxes and amortization of investment tax credits
(30
)
 
2

Other non-cash operating activities
34

 
7

Changes in assets and liabilities:
 
 
 
Accounts receivable
(23
)
 
(11
)
Receivables from and payables to affiliates, net
9

 
(9
)
Inventories
2

 
(1
)
Accounts payable and accrued expenses
17

 
16

Income taxes
2

 
6

Pension and non-pension postretirement benefit contributions
(2
)
 
—

Other assets and liabilities
(68
)
 
(44
)
Net cash flows provided by operating activities
58

 
61

Cash flows from investing activities
 
 
 
Capital expenditures
(178
)
 
(227
)
Other investing activities
5

 
—

Net cash flows used in investing activities
(173
)
 
(227
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
(65
)
 
13

Repayments of short-term borrowings with maturities greater than 90 days
—

 
(125
)
Issuance of long-term debt
123

 
150

Retirement of long-term debt
(34
)
 
(9
)
Changes in PHI intercompany money pool
5


—

Dividends paid on common stock
(35
)
 
(24
)
Contributions from parent
116

 
155

Other financing activities
(1
)
 
(1
)
Net cash flows provided by financing activities
109

 
159

Decrease in cash, cash equivalents and restricted cash
(6
)
 
(7
)
Cash, cash equivalents and restricted cash at beginning of period
28

 
30

Cash, cash equivalents and restricted cash at end of period
$
22


$
23

 
 
 
 
Supplemental cash flow information
 
 
 
Increase (decrease) in capital expenditures not paid
$
7

 
$
(35
)

See the Combined Notes to Consolidated Financial Statements
52
Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
June 30, 2020
 
December 31, 2019
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
8

 
$
12

Restricted cash and cash equivalents
3

 
2

Accounts receivable
 
 
 
Customer accounts receivable
137
 
121
Customer allowance for credit losses
(20)
 
(13)
Customer accounts receivable, net
117

 
108

Other accounts receivable
59
 
53
Other allowance for credit losses
(8)
 
(5)
Other accounts receivable, net
51

 
48

Receivables from affiliates
1

 
4

Inventories, net
32

 
34

Prepaid utility taxes
34

 
—

Regulatory assets
71

 
57

Other
4

 
5

Total current assets
321

 
270

Property, plant and equipment (net of accumulated depreciation and amortization of $1,261 and $1,210 as of June 30, 2020 and December 31, 2019, respectively)
3,302

 
3,190

Deferred debits and other assets
 
 
 
Regulatory assets
369

 
368

Prepaid pension asset
47

 
52

Other
50

 
53

Total deferred debits and other assets
466

 
473

Total assets(a)
$
4,089

 
$
3,933


See the Combined Notes to Consolidated Financial Statements
53
Table of Contents

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

(In millions)
June 30, 2020
 
December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
5

 
$
70

Long-term debt due within one year
260

 
20

Accounts payable
170

 
144

Accrued expenses
39

 
42

Payables to affiliates
31

 
25

Borrowings from PHI intercompany money pool

5

 
—

Customer deposits
24

 
25

Regulatory liabilities
40

 
25

Other
8

 
9

Total current liabilities
582

 
360

Long-term debt
1,160

 
1,307

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
590

 
577

Non-pension postretirement benefit obligations
17

 
17

Regulatory liabilities
312

 
357

Other
40

 
39

Total deferred credits and other liabilities
959

 
990

Total liabilities(a)
2,701

 
2,657

Commitments and contingencies

 

Shareholder's equity
 
 
 
Common stock
1,270

 
1,154

Retained earnings
118

 
122

Total shareholder's equity
1,388


1,276

Total liabilities and shareholder's equity
$
4,089


$
3,933

__________
(a)
ACE’s consolidated total assets include $14 million and $17 million at June 30, 2020 and December 31, 2019, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $31 million and $41 million at June 30, 2020 and December 31, 2019, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 16 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements
54
Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
 
Six Months Ended June 30, 2020
(In millions)
Common Stock
 
Retained Earnings
 
Total Shareholder's Equity
Balance, December 31, 2019
$
1,154

 
$
122

 
$
1,276

Net income
—

 
13

 
13

Common stock dividends
—

 
(23
)
 
(23
)
Contributions from parent
1

 
—

 
1

Balance, March 31, 2020
1,155

 
112

 
1,267

Net income
—

 
18

 
18

Common stock dividends
—

 
(12
)
 
(12
)
Contributions from parent
115

 
—

 
115

Balance, June 30, 2020
$
1,270


$
118

 
$
1,388


 
Six Months Ended June 30, 2019
(In millions)
Common Stock
 
Retained Earnings
 
Total Shareholder's Equity
Balance, December 31, 2018
$
979

 
$
147

 
$
1,126

Net income
—

 
10

 
10

Common stock dividends
—

 
(12
)
 
(12
)
Contributions from parent
5

 
—

 
5

Balance, March 31, 2019
984

 
145

 
1,129

Net income
—

 
14

 
14

Common stock dividends
—

 
(12
)
 
(12
)
Contributions from parent
150

 
—

 
150

Balance, June 30, 2019
$
1,134


$
147

 
$
1,281



See the Combined Notes to Consolidated Financial Statements
55
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)

Note 1 — Significant Accounting Policies


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

Basis of Presentation (All Registrants)
Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
The accompanying consolidated financial statements as of June 30, 2020 and December 31, 2019 and for the three and six months ended June 30, 2020 and 2019 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, 2019 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

56
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)

Note 1 — Significant Accounting Policies

interim period or for the fiscal year ending December 31, 2020. 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.
COVID-19 (All Registrants)
The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19). The Registrants provide a critical service to their customers and have taken measures to keep employees who operate the business safe and minimize unnecessary risk of exposure to the virus, including extra precautions for employees who work in the field. The Registrants have implemented work from home policies where appropriate and imposed travel limitations on employees. In addition, the Registrants have updated their existing business continuity plans.

Management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and accompanying notes, and the amounts of revenues and expenses reported during the periods covered by those financial statements and accompanying notes. Management assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, our allowance for credit losses, the carrying value of our goodwill and other long-lived assets, in context with the information reasonably available to us and the unknown future impacts of COVID-19 as of June 30, 2020 and through the date of this report. The Registrants' future assessment of our current expectations of the magnitude and duration of COVID-19, as well as other factors, could result in material impacts to their consolidated financial statements in future reporting periods.
New Accounting Standards (All Registrants)
New Accounting Standards Adopted as of January 1, 2020: The following new authoritative accounting guidance issued by the FASB was adopted as of January 1, 2020 and was reflected by the Registrants in their consolidated financial statements beginning in the first quarter of 2020.
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 its current estimate of credit losses expected to be incurred over the life of the financial instrument based on historical experience, current conditions and reasonable and supportable forecasts. The standard was effective January 1, 2020 and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. This standard was primarily applicable to Generation's and the Utility Registrants' Customer accounts receivables balances. This guidance did not have a significant impact on the Registrants’ consolidated financial statements.
Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. The standard was effective January 1, 2020 and must be applied on a prospective basis. Exelon, Generation, ComEd, PHI and DPL will apply the new guidance for their goodwill impairment assessments in 2020 and do not expect the updated guidance to have a material impact to their financial statements.
Allowance for Credit Losses on Accounts Receivables (All Registrants)

The allowance for credit losses reflects the Registrants’ best estimates of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts.

The allowance for credit losses for Generation’s retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the

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

Note 1 — Significant Accounting Policies

exercise of collateral calls. The allowance for credit losses for Generation wholesale customers is developed using a credit monitoring process, similar to that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, Generation uses specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense on Generation’s Consolidated Statements of Operations and Comprehensive Income.

The allowance for credit losses for the Utility Registrants’ customers is developed by applying loss rates for each Utility Registrant, based on historical loss experience, current conditions and forward-looking risk factors, to the outstanding receivable balance by customer risk segment. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Adjustments to the allowance for credit losses are primarily recorded to Operating and maintenance expense on the Utility Registrants' Consolidated Statements of Operations and Comprehensive Income and Regulatory assets on ComEd, BGE, Pepco, DPL and ACE’s Consolidated Balance Sheets. See Note 3 - Regulatory Matters of the 2019 Form 10-K for additional information regarding the regulatory recovery of credit losses on customer accounts receivable at ComEd, BGE, Pepco, DPL and ACE.

The Registrants have certain non-customer receivables in Other deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties with no history of default.  As such, the allowance for credit losses related to these receivables is not material.  The Registrants monitor these balances and will record an allowance if there are indicators of a decline in credit quality.

2. Regulatory Matters (All Registrants)
As discussed in Note 3 — Regulatory Matters of the Exelon 2019 Form 10-K, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The following discusses developments in 2020 and updates to the 2019 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 2020.

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

Note 2 — Regulatory Matters

Completed Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Requested Revenue Requirement (Decrease) Increase
 
Approved Revenue Requirement (Decrease) Increase
 
Approved ROE
 
Approval Date
Rate Effective Date
ComEd - Illinois (Electric)(a)
April 8, 2019
$
(6
)
 
$
(17
)
 
8.91
%
 
December 4, 2019
January 1, 2020
DPL - Maryland (Electric)
December 5, 2019 (amended April 23, 2020)
17

 
12

 
9.60
%
 
July 14, 2020
July 16, 2020

__________
(a)
Reflects an increase of $51 million for the initial revenue requirement for 2019 and a decrease of $68 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 6.51%, inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points.
Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Requested Revenue Requirement (Decrease) Increase
Requested ROE
Expected Approval Timing
ComEd - Illinois (Electric)(a)
April 16, 2020
$
(11
)
8.38
%
Fourth quarter of 2020
BGE - Maryland (Electric and Natural Gas)(b)
May 15, 2020
235

10.1
%
Fourth quarter of 2020
Pepco - District of Columbia (Electric)(c)
May 30, 2019 (amended June 1, 2020)
136

9.7
%
Fourth quarter of 2020
DPL - Delaware (Natural Gas)(d)
February 21, 2020 (amended March 17, 2020)
9

10.3
%
First quarter of 2021
DPL - Delaware (Electric)(e)
March 6, 2020 (amended April 16, 2020)
24

10.3
%
Second quarter of 2021
__________
(a)
Reflects an increase of $51 million for the initial revenue requirement for 2020 and a decrease of $62 million related to the annual reconciliation for 2019. The revenue requirement for 2020 and annual reconciliation for 2019 provides for a weighted average debt and equity return on distribution rate base of 6.28%, inclusive of an allowed ROE of 8.38%, reflecting the average rate on 30-year treasury notes plus 580 basis points.
(b)
Reflects a three-year cumulative multi-year plan for 2021 through 2023 and total requested revenue requirement increases in 2023 of $140 million related to electric distribution and $95 million related to natural gas distribution to recover capital investments made in late 2019 and planned capital investments from 2020 to 2023.
(c)
Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects a three-year cumulative multi-year plan and requested revenue requirement increases of $73 million and $63 million for 2022 and 2023, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.
(d)
The rates will go into effect on September 21, 2020, subject to refund.
(e)
The rates will go into effect on October 6, 2020, subject to refund.
Transmission Formula Rates

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

Note 2 — Regulatory Matters

Transmission Formula Rate (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or before May 15 and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd, BGE, DPL and ACE is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for Pepco is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense and accumulated deferred income taxes. The update for ComEd, BGE, DPL and ACE also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The update for PECO and Pepco also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2020, the following total increases/(decreases) were included in ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:
Registrant(a)
Initial Revenue Requirement Increase (Decrease)
Annual Reconciliation Decrease
Total Revenue Requirement Increase (Decrease)(c)
 
Allowed Return on Rate Base(d)
Allowed ROE(e)
ComEd
$
18

$
(4
)
$
14

 
8.17
%
11.50
%
PECO(b)
5

(28
)
(23
)
 
7.47
%
10.35
%
BGE
16

(3
)
4

 
7.26
%
10.50
%
Pepco
2

(46
)
(44
)
 
7.81
%
10.50
%
DPL
(4
)
(40
)
(44
)
 
7.20
%
10.50
%
ACE
5

(25
)
(20
)
 
7.40
%
10.50
%
__________
(a)
All rates are effective June 2020, subject to review by interested parties, which is anticipated to be completed by the fourth quarter of 2020 or first quarter of 2021 for ComEd, BGE, Pepco, DPL and ACE and second quarter of 2021 for PECO.
(b)
PECO posted a revised filing to the PJM website on July 17, 2020 reflecting updates to the formula rate based on the FERC order dated July 9, 2020.
(c)
The decrease in PECO's transmission revenue requirement relates to refunds from December 1, 2017, in accordance with the settlement agreement dated July 22, 2019. The change in BGE's transmission revenue requirement includes a $9 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE. ComEd, BGE, Pepco, DPL and ACE’s transmission revenue requirement include a decrease related to the April 24, 2020 settlement agreement related to excess deferred income taxes. Refer to Transmission-Related Income Tax Regulatory Assets below for additional information.
(d)
Represents the weighted average debt and equity return on transmission rate bases.
(e)
As part of the FERC-approved settlements of ComEd’s 2007 and PECO's 2017 transmission rate cases, the rate of return on common equity is 11.50% and 10.35%, respectively, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55% and 55.75%, respectively. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.

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

Note 2 — Regulatory Matters

Other State Regulatory Matters
Illinois Regulatory Matters
Energy Efficiency Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on May 21, 2020.  The filing establishes the revenue requirement used to set the rates that will take effect in January 2021 after the ICC’s review and approval. The revenue requirement requested is based on a reconciliation of the 2019 actual costs plus projected 2020 and 2021 expenditures.
Initial Revenue Requirement Increase
Annual Reconciliation Increase
Total Revenue Requirement Increase
 
Requested Return on Rate Base
Requested ROE
$
45

$
3

$
48

(a) 
6.28
%
8.38
%
__________
(a)
The requested revenue requirement increase provides for a weighted average debt and equity return on rate base of 6.28% inclusive of an allowed ROE of 8.38%. The ROE reflects the average rate on 30-year treasury notes plus 580 basis points. The ROE applicable to the 2019 reconciliation year is 8.96% and the return on rate base is 6.56%, which includes a performance adjustment that can either increase or decrease the ROE.
Other Federal Regulatory Matters
Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. 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. In the fourth quarter of 2017, ComEd, BGE, Pepco, DPL, and ACE fully impaired their associated transmission-related income tax regulatory asset for the portion of the income tax regulatory asset that would have been previously amortized.
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 1) BGE's rehearing request of FERC's November 16, 2017 order; and 2) February 23, 2018 (as amended on July 9, 2018) filing by ComEd, Pepco, DPL and ACE for similar recovery.
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 March 27, 2020, the Court of Appeals denied BGE’s November 2, 2018 appeal.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover only ongoing non-TCJA amortization amounts and credit TCJA transmission-related income tax regulatory liabilities to customers for the prospective period starting on October 1, 2018. 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. On April 24, 2020, ComEd, BGE, Pepco, DPL, ACE and other parties filed a settlement agreement with FERC. The settlement agreement provides for the recovery of ongoing transmission-related income tax regulatory assets and establishes the amount and amortization period for excess deferred income taxes resulting from TCJA. The settlement resulted in a reduction to Operating revenues and an offsetting reduction to Income tax expense in the second quarter of 2020.
While FERC has no deadline by which it must rule on the settlement, a final order from FERC is expected in the third quarter of 2020. Exelon cannot predict the outcome of this proceeding. 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 $83 million, $51 million, $19 million, $13 million, $5 million, $6 million and $2 million, respectively, as of June 30, 2020.

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

Note 2 — Regulatory Matters

Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2019, unless noted below. See Note 3 — Regulatory Matters of the Exelon 2019 Form 10-K for additional information on the specific regulatory assets and liabilities.
ComEd. Regulatory assets increased $120 million primarily due to an increase of $94 million in the Energy Efficiency Costs regulatory asset and $17 million in the Renewable Energy regulatory asset.
PECO. Regulatory assets increased $55 million primarily due to an increase of $54 million in the Deferred Income Taxes regulatory asset. Regulatory liabilities decreased $81 million primarily due to a decrease of $104 million in the Nuclear Decommissioning regulatory liability offset by a $25 million increase in the Electric Energy and Natural Gas Costs regulatory liability.
ACE. Regulatory liabilities decreased $30 million primarily due to a decrease of $44 million in the Deferred Income Taxes regulatory liability offset by a $18 million increase in Transmission FERC Formula Rate regulatory liability.
Capitalized Ratemaking Amounts Not Recognized (Exelon and the Utility Registrants)
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.
 
Exelon
 
ComEd(a)
 
PECO
 
BGE(b)
 
PHI
 
Pepco(c)
 
DPL(c)
 
ACE
June 30, 2020
$
57

 
$
1

 
$
—

 
$
49

 
$
7

 
$
4

 
$
3

 
$
—

December 31, 2019
63

 
3

 
—

 
53

 
7

 
4

 
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)
New Jersey Regulatory Matters
New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $17 million and $35 million for the three and six months ended June 30, 2020 and $10 million for the three and six months ended June 30, 2019. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. Exelon and Generation cannot predict the outcome of the appeal. See Note 6 — Early Plant Retirements for additional information related to Salem.
New York Regulatory Matters
New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC to be Generation's FitzPatrick, Ginna and Nine Mile Point nuclear facilities.

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

Note 2 — Regulatory Matters

On November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. 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. On October 8, 2019, the court dismissed all remaining claims. The petitioners filed a notice of appeal on November 4, 2019 and originally had until May 4, 2020 to file their brief. Due to COVID-19 related restrictions, the court extended the deadline to July 29, 2020 and, as of August 4, 2020, no brief has been received.
See Note 6 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.
Federal Regulatory Matters
PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR). If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a state government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the MOPR in NYISO applies only to certain resources in downstate New York.
For Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions. While FERC issued a set of orders on MOPR in NYISO on February 20, 2020, it did not expand mitigation to include Generation's nuclear assets in upstate New York. However, FERC has taken action to expand the MOPR in PJM.
On December 19, 2019, FERC required PJM to broadly apply the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage and all resources owned by vertically-integrated utilities. This greatly expands the breadth and scope of PJM’s MOPR, which is effective as of PJM’s next capacity auction. While FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources.
FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism (under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone). In response to FERC’s order PJM submitted a compliance filing on March 18, 2020 wherein PJM proposes tariff language interpreting and implementing FERC's directives and proposes a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing. FERC has no deadline for such action, and FERC could accept, reject or direct further revisions to all or part of PJM's proposed tariff revisions and auction schedule.
On April 16, 2020, FERC issued an order largely denying requests for rehearing of FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing that could also delay the timing for FERC to issue its compliance order(s) which PJM submitted on June 1, 2020. PJM cannot resume activities related to its capacity auctions until FERC acts on these compliance filings.
FERC issued an order on May 21, 2020 involving reforms to PJM’s day-ahead and real-time reserves markets that may require further changes to the MOPR levels pending before FERC in the PJM MOPR Proceeding. In approving reforms to PJM’s reserves markets, FERC also directed PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services (referred to as the Energy and Ancillary Services Offset) and to use that new methodology in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. FERC directed PJM to submit its new Energy and Ancillary Services Offset revenue projection methodology no later than August 5, 2020. On review of this compliance filing, FERC will address how these additional reforms will impact MOPR levels and the timeline for implementing the new revenue projection methodology, including any potential impacts on auction timing.
Unless Illinois and New Jersey can implement an FRR program in their PJM zones, the MOPR will apply in the next capacity auction to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES or the New Jersey ZEC program, as applicable, increasing the risk that those units may not clear the capacity market.

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

Note 2 — Regulatory Matters

Exelon is currently working with PJM and other stakeholders to pursue the FRR option prior to the next capacity auction in PJM. If Illinois implements the FRR option, Generation’s Illinois nuclear plants could be removed from PJM’s capacity auction and instead supply capacity and be compensated under the FRR program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 6 - Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative and regulatory changes. Legislation may be introduced in New Jersey as well. Exelon cannot predict whether or when such legislative and regulatory changes can be implemented.
If Generation’s state-supported nuclear plants in PJM are subjected to the MOPR or equivalent without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial statements, which Exelon and Generation cannot reasonably estimate at this time.
Operating License Renewals
Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, Generation has been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.
On October 29, 2019, Generation and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act. Among the Proposed License Articles are modifications to river flows to improve aquatic habitat, eel passage improvements and initiatives to support rare, threatened and endangered wildlife. If FERC approves the Offer of Settlement and incorporates the Proposed License Articles into the new license without modification, then MDE would waive its rights to issue a 401 Certification and Generation would agree, pursuant to a separate agreement with MDE (MDE Settlement), to implement additional environmental protection, mitigation and enhancement measures over the anticipated 50-year term of the new license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. Exelon’s commitments under the various provisions of the Offer of Settlement and MDE Settlement are not effective unless and until FERC approves the Offer of Settlement and issues the new license with the Proposed License Articles. Generation cannot currently predict when FERC will issue the new license.
Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3, which was approved on March 6, 2020. Peach Bottom Units 2 and 3 are now licensed to operate through 2053 and 2054, respectively.
3. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution and transmission services.
See Note 4 — Revenue from Contracts with Customers of the Exelon 2019 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.
Contract Balances (All Registrants)
Contract Assets and Liabilities
Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Customer accounts receivable, net, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets.

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

Note 3 — Revenue from Contracts with Customers

Generation records contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. Generation records contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon's and Generation's Consolidated Balance Sheets.
The following table provides a rollforward of the contract assets and liabilities reflected in Exelon's and Generation's Consolidated Balance Sheets for the three and six months ended June 30, 2020 and 2019.
 
 
Contract Assets
 
Contract Liabilities
 
 
Exelon
 
Generation
 
Exelon
 
Generation
Balance as of December 31, 2019
 
$
174

 
$
174

 
$
33

 
$
71

Consideration received or due
 
(19
)
 
(19
)
 
20

 
55

Revenues recognized (a)
 
17

 
17

 
(24
)
 
(70
)
Balance at March 31, 2020
 
$
172

 
$
172

 
$
29

 
$
56

Consideration received or due
 
(26
)
 
(26
)
 
13

 
34

Revenues recognized (a)
 
13

 
13

 
(22
)
 
(63
)
Balance at June 30, 2020
 
$
159

 
$
159

 
$
20

 
$
27

 
 
 
 
 
 
 
 
 
Balance as of December 31, 2018
 
$
187

 
$
187

 
$
27

 
$
42

Consideration received or due
 
(26
)
 
(26
)
 
21

 
63

Revenues recognized (b)
 
26

 
26

 
(23
)
 
(66
)
Balance at March 31, 2019
 
$
187

 
$
187

 
$
25

 
$
39

Consideration received or due
 
(18
)
 
(18
)
 
17

 
52

Revenues recognized (b)
 
27

 
27

 
(21
)
 
(65
)
Balance at June 30, 2019
 
$
196

 
$
196

 
$
21

 
$
26


__________
(a)
Revenues recognized in the three and six months ended June 30, 2020, which were included in contract liabilities at December 31, 2019, were approximately $14 million and $23 million, respectively, for Exelon and $42 million and $61 million, respectively, for Generation.
(b)
Revenues recognized in the three and six months ended June 30, 2019, which were included in contract liabilities at December 31, 2018, were approximately $9 million and $14 million, respectively, for Exelon and $24 million and $28 million, respectively, for Generation.
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, 2020 and December 31, 2019, the Utility Registrants' contract liabilities were not material.
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, 2020. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
This disclosure excludes Generation's power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.

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

Note 3 — Revenue from Contracts with Customers

 
2020
 
2021
 
2022
 
2023
 
2024 and thereafter
 
Total
Exelon
$
169

 
$
194

 
$
73

 
$
43

 
$
189

 
$
668

Generation
231

 
282

 
105

 
48

 
189

 
855


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 4 — Segment Information for the presentation of the Registrant's revenue disaggregation.
4. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources at each of the Registrants.
Exelon has eleven reportable segments, which include Generation's five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, and PHI's 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.
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 five 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 NYISO.
•
ERCOT represents operations within Electric Reliability Council of Texas.
•
Other Power Regions:
•
New England represents the operations within ISO-NE.
•
South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM.
•
West represents operations in the WECC, which includes California ISO.
•
Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.
The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ 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

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

Note 4 — Segment Information

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.
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, 2020 and 2019 is as follows:
Three Months Ended June 30, 2020 and 2019
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Other(a)
 
Intersegment
Eliminations
 
Exelon
Operating revenues(b):
2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Competitive businesses electric revenues
$
3,414

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(268
)
 
$
3,146

Competitive businesses natural gas revenues
353

 
—

 
—

 
—

 
—

 
—

 
—

 
353

Competitive businesses other revenues
113

 
—

 
—

 
—

 
—

 
—

 
(1
)
 
112

Rate-regulated electric revenues
—

 
1,417

 
586

 
504

 
983

 
—

 
(15
)
 
3,475

Rate-regulated natural gas revenues
—

 
—

 
95

 
112

 
30

 
—

 
(1
)
 
236

Shared service and other revenues
—

 
—

 
—

 
—

 
3

 
472

 
(475
)
 
—

Total operating revenues
$
3,880

 
$
1,417

 
$
681

 
$
616

 
$
1,016

 
$
472

 
$
(760
)
 
$
7,322

2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Competitive businesses electric revenues
$
3,718

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(250
)
 
$
3,468

Competitive businesses natural gas revenues
333

 
—

 
—

 
—

 
—

 
—

 
—

 
333

Competitive businesses other revenues
159

 
—

 
—

 
—

 
—

 
—

 
(1
)
 
158

Rate-regulated electric revenues
—

 
1,351

 
566

 
540

 
1,063

 
—

 
(8
)
 
3,512

Rate-regulated natural gas revenues
—

 
—

 
89

 
109

 
24

 
—

 
(4
)
 
218

Shared service and other revenues
—

 
—

 
—

 
—

 
4

 
484

 
(488
)
 
—

Total operating revenues
$
4,210

 
$
1,351

 
$
655

 
$
649

 
$
1,091

 
$
484

 
$
(751
)
 
$
7,689

Intersegment revenues(c):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
271

 
$
11

 
$
2

 
$
4

 
$
3

 
$
470

 
$
(760
)
 
$
1

2019
252

 
5

 
2

 
6

 
3

 
482

 
(750
)
 
—

Depreciation and amortization:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
300

 
$
274

 
$
88

 
$
129

 
$
191

 
$
19

 
$
—

 
$
1,001

2019
409

 
257

 
83

 
117

 
188

 
25

 
—

 
1,079


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

Note 4 — Segment Information

 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Other(a)
 
Intersegment
Eliminations
 
Exelon
Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
3,547

 
$
1,345

 
$
618

 
$
573

 
$
956

 
$
478

 
$
(748
)
 
$
6,769

2019
4,096

 
1,040

 
510

 
569

 
926

 
484

 
(744
)
 
6,881

Interest expense, net:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
87

 
$
98

 
$
36

 
$
32

 
$
67

 
$
107

 
$
—

 
$
427

2019
116

 
89

 
33

 
29

 
67

 
75

 
—

 
409

Income (loss) before income taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
860

 
$
(15
)
 
$
32

 
$
17

 
$
7

 
$
(108
)
 
$
1

 
$
794

2019
202

 
232

 
115

 
56

 
112

 
(73
)
 
—

 
644

Income Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
329

 
$
46

 
$
(7
)
 
$
(22
)
 
$
(87
)
 
$
(40
)
 
$
—

 
$
219

2019
78

 
46

 
13

 
11

 
6

 
(10
)
 
—

 
144

Net income (loss):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
529

 
$
(61
)
 
$
39

 
$
39

 
$
94

 
$
(67
)
 
$
1

 
$
574

2019
118

 
186

 
102

 
45

 
106

 
(63
)
 
—

 
494

Capital Expenditures
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
372

 
$
523

 
$
253

 
$
265

 
$
310

 
$
34

 
$
—

 
$
1,757

2019
383

 
459

 
225

 
284

 
340

 
11

 
—

 
1,702

__________
(a)
Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(b)
Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(c)
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. See Note 18 — Related Party Transactions for additional information on intersegment revenues.



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

Note 4 — Segment Information

PHI:
 
Pepco
 
DPL
 
ACE
 
Other(a)
 
Intersegment
Eliminations
 
PHI
Operating revenues(b):
 
 
 
 
 
 
 
 
 
 
 
2020
 
 
 
 
 
 
 
 
 
 
 
Rate-regulated electric revenues
$
494

 
$
237

 
$
256

 
$
—

 
$
(4
)
 
$
983

Rate-regulated natural gas revenues
—

 
30

 
—

 
—

 
—

 
30

Shared service and other revenues
—

 
—

 
—

 
97

 
(94
)
 
3

Total operating revenues
$
494

 
$
267

 
$
256

 
$
97

 
$
(98
)
 
$
1,016

2019
 
 
 
 
 
 
 
 
 
 
 
Rate-regulated electric revenues
$
531

 
$
261

 
$
274

 
$
—

 
$
(3
)
 
$
1,063

Rate-regulated natural gas revenues
—

 
24

 
—

 
—

 
—

 
24

Shared service and other revenues
—

 
2

 
—

 
97

 
(95
)
 
4

Total operating revenues
$
531

 
$
287

 
$
274

 
$
97

 
$
(98
)
 
$
1,091

Intersegment revenues(c):
 
 
 
 
 
 
 
 
 
 
 
2020
$
1

 
$
2

 
$
1

 
$
97

 
$
(98
)
 
$
3

2019
1

 
2

 
1

 
98

 
(99
)
 
3

Depreciation and amortization:
 
 
 
 
 
 
 
 
 
 
 
2020
$
92

 
$
47

 
$
44

 
$
8

 
$
—

 
$
191

2019
93

 
45

 
40

 
10

 
—

 
188

Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
2020
$
436

 
$
263

 
$
258

 
$
97

 
$
(98
)
 
$
956

2019
438

 
243

 
246

 
100

 
(101
)
 
926

Interest expense, net:
 
 
 
 
 
 
 
 
 
 
 
2020
$
34

 
$
15

 
$
15

 
$
3

 
$
—

 
$
67

2019
34

 
15

 
15

 
3

 
—

 
67

Income (loss) before income taxes:
 
 
 
 
 
 
 
 
 
 
 
2020
$
33

 
$
(9
)
 
$
(15
)
 
$
(2
)
 
$
—

 
$
7

2019(d)
66

 
34

 
14

 
(2
)
 
—

 
112

Income Taxes:
 
 
 
 
 
 
 
 
 
 
 
2020
$
(24
)
 
$
(28
)
 
$
(33
)
 
$
(2
)
 
$
—

 
$
(87
)
2019
2

 
4

 
—

 
—

 
—

 
6

Net income (loss):
 
 
 
 
 
 
 
 
 
 
 
2020
$
57

 
$
19

 
$
18

 
$
—

 
$
—

 
$
94

2019
64

 
30

 
14

 
(2
)
 
—

 
106

Capital Expenditures
 
 
 
 
 
 
 
 
 
 
 
2020
$
144

 
$
89

 
$
77

 
$
—

 
$
—

 
$
310

2019
154

 
82

 
99

 
5

 
—

 
340

__________
(a)
Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
(b)
Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(c)
Includes intersegment revenues with ComEd, BGE and PECO, which are eliminated at Exelon.
(d)
The Income (loss) before income taxes amounts in Other and Intersegment Eliminations have been adjusted by an offsetting $108 million for consistency with the Exelon consolidating disclosure above.


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

Note 4 — Segment Information


The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
 
Three Months Ended June 30, 2020
 
Revenues from external customers(a)
 
Intersegment
Revenues
 
Total
Revenues
 
Contracts with customers
 
Other(b)
 
Total
 
 
Mid-Atlantic
$
1,100

 
$
(35
)
 
$
1,065

 
$
9

 
$
1,074

Midwest
855

 
107

 
962

 
—

 
962

New York
336

 
5

 
341

 
(1
)
 
340

ERCOT
175

 
52

 
227

 
7

 
234

Other Power Regions
776

 
43

 
819

 
(15
)
 
804

Total Competitive Businesses Electric Revenues
3,242

 
172

 
3,414

 
—

 
3,414

Competitive Businesses Natural Gas Revenues
209

 
144

 
353

 
—

 
353

Competitive Businesses Other Revenues(c)
86

 
27

 
113

 
—

 
113

Total Generation Consolidated Operating Revenues
$
3,537

 
$
343

 
$
3,880

 
$
—

 
$
3,880

 
Three Months Ended June 30, 2019
 
Revenues from external customers(a)
 
Intersegment
revenues
 
Total
Revenues
 
Contracts with customers
 
Other(b)
 
Total
 
 
Mid-Atlantic
$
1,162

 
$
21

 
$
1,183

 
$
6

 
$
1,189

Midwest
974

 
68

 
1,042

 
(8
)
 
1,034

New York
373

 
17

 
390

 
—

 
390

ERCOT
178

 
47

 
225

 
4

 
229

Other Power Regions
814

 
64

 
878

 
(17
)
 
861

Total Competitive Businesses Electric Revenues
3,501

 
217

 
3,718

 
(15
)
 
3,703

Competitive Businesses Natural Gas Revenues
177

 
156

 
333

 
15

 
348

Competitive Businesses Other Revenues(c)
108

 
51

 
159

 
—

 
159

Total Generation Consolidated Operating Revenues
$
3,786

 
$
424

 
$
4,210

 
$
—

 
$
4,210

__________
(a)
Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)
Includes revenues from derivatives and leases.
(c)
Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $21 million and $38 million in 2020 and 2019, respectively, and elimination of intersegment revenues.


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

Note 4 — Segment Information

Revenues net of purchased power and fuel expense (Generation):
 
Three Months Ended June 30, 2020
 
Three Months Ended June 30, 2019
 
RNF
from external
customers(a)
 
Intersegment
RNF
 
Total RNF
 
RNF
from external
customers(a)
 
Intersegment
RNF
 
Total RNF
Mid-Atlantic
$
516

 
$
9

 
$
525

 
$
644

 
$
8

 
$
652

Midwest
702

 
1

 
703

 
738

 
(8
)
 
730

New York
243

 
3

 
246

 
250

 
3

 
253

ERCOT
92

 
5

 
97

 
80

 
(1
)
 
79

Other Power Regions
181

 
(24
)
 
157

 
154

 
(20
)
 
134

Total Revenues net of purchased power and fuel expense for Reportable Segments
1,734


(6
)

1,728


1,866


(18
)

1,848

Other(b)
204

 
6

 
210

 
52

 
18

 
70

Total Generation Revenues net of purchased power and fuel expense
$
1,938

 
$
—

 
$
1,938

 
$
1,918

 
$
—

 
$
1,918

__________
(a)
Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)
Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $85 million and losses of $74 million in 2020 and 2019, respectively and the elimination of intersegment RNF.



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

Note 4 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):
 
Three Months Ended June 30, 2020
Revenues from contracts with customers
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Rate-regulated electric revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
767

 
$
377

 
$
304

 
$
529

 
$
237

 
$
147

 
$
145

Small commercial & industrial
327

 
88

 
51

 
105

 
29

 
39

 
37

Large commercial & industrial
119

 
55

 
94

 
240

 
175

 
22

 
43

Public authorities & electric railroads
11

 
7

 
7

 
15

 
8

 
3

 
4

Other(a)
218

 
55

 
76

 
161

 
58

 
51

 
53

Total rate-regulated electric revenues(b)
$
1,442

 
$
582

 
$
532

 
$
1,050

 
$
507

 
$
262

 
$
282

Rate-regulated natural gas revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
—

 
$
70

 
$
81

 
$
17

 
$
—

 
$
17

 
$
—

Small commercial & industrial
—

 
19

 
12

 
8

 
—

 
8

 
—

Large commercial & industrial
—

 
—

 
24

 
1

 
—

 
1

 
—

Transportation
—

 
6

 
—

 
3

 
—

 
3

 
—

Other(c)
—

 
1

 
3

 
1

 
—

 
1

 
—

Total rate-regulated natural gas revenues(d)
$
—

 
$
96

 
$
120

 
$
30

 
$
—

 
$
30

 
$
—

Total rate-regulated revenues from contracts with customers
$
1,442

 
$
678

 
$
652

 
$
1,080

 
$
507

 
$
292

 
$
282

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from alternative revenue programs
$
(25
)
 
$
4

 
$
(37
)
 
$
(64
)
 
$
(13
)
 
$
(25
)
 
$
(26
)
Other rate-regulated electric revenues(e)
—

 
—

 
1

 
—

 
—

 
—

 
—

Other rate-regulated natural gas revenues(e)
—

 
(1
)
 
—

 
—

 
—

 
—

 
—

Total other revenues
$
(25
)
 
$
3

 
$
(36
)
 
$
(64
)
 
$
(13
)
 
$
(25
)
 
$
(26
)
Total rate-regulated revenues for reportable segments
$
1,417

 
$
681

 
$
616

 
$
1,016

 
$
494

 
$
267

 
$
256


72
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Segment Information

 
Three Months Ended June 30, 2019
Revenues from contracts with customers
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Rate-regulated electric revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
647

 
$
343

 
$
282

 
$
494

 
$
224

 
$
135

 
$
135

Small commercial & industrial
349

 
99

 
59

 
120

 
35

 
44

 
41

Large commercial & industrial
127

 
52

 
109

 
278

 
207

 
25

 
46

Public authorities & electric railroads
10

 
7

 
6

 
16

 
8

 
4

 
4

Other(a)
227

 
62

 
82

 
159

 
56

 
54

 
50

Total rate-regulated electric revenues(b)
$
1,360

 
$
563

 
$
538

 
$
1,067

 
$
530

 
$
262

 
$
276

Rate-regulated natural gas revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
—

 
$
49

 
$
60

 
$
11

 
$
—

 
$
11

 
$
—

Small commercial & industrial
—

 
33

 
11

 
7

 
—

 
7

 
—

Large commercial & industrial
—

 
—

 
23

 
2

 
—

 
2

 
—

Transportation
—

 
6

 
—

 
3

 
—

 
3

 
—

Other(c)
—

 
1

 
7

 
1

 
—

 
1

 
—

Total rate-regulated natural gas revenues(d)
$
—

 
$
89

 
$
101

 
$
24

 
$
—

 
$
24

 
$
—

Total rate-regulated revenues from contracts with customers
$
1,360

 
$
652

 
$
639

 
$
1,091

 
$
530

 
$
286

 
$
276

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from alternative revenue programs
$
(14
)
 
$
(3
)
 
$
6

 
$
(3
)
 
$
(1
)
 
$
—

 
$
(2
)
Other rate-regulated electric revenues(e)
5

 
6

 
3

 
3

 
2

 
1

 
—

Other rate-regulated natural gas revenues(e)
—

 
—

 
1

 
—

 
—

 
—

 
—

Total other revenues
$
(9
)
 
$
3

 
$
10

 
$
—

 
$
1

 
$
1

 
$
(2
)
Total rate-regulated revenues for reportable segments
$
1,351

 
$
655

 
$
649

 
$
1,091

 
$
531

 
$
287

 
$
274

__________
(a)
Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)
Includes operating revenues from affiliates of $11 million, $1 million, $3 million, $3 million, $1 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2020 and $5 million, $1 million, $1 million, $3 million, $1 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019.
(c)
Includes revenues from off-system natural gas sales.
(d)
Includes operating revenues from affiliates of less than $1 million and $1 million at PECO and BGE, respectively, in 2020 and less than $1 million and $4 million at PECO and BGE, respectively, in 2019.
(e)
Includes late payment charge revenues.

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

Note 4 — Segment Information

Six Months Ended June 30, 2020 and 2019
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Other(a)
 
Intersegment
Eliminations
 
Exelon
Operating revenues(b):
2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Competitive businesses electric revenues
$
7,165

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(594
)
 
$
6,571

Competitive businesses natural gas revenues
1,025

 
—

 
—

 
—

 
—

 
—

 
(3
)
 
1,022

Competitive businesses other revenues
423

 
—

 
—

 
—

 
—

 
—

 
(2
)
 
421

Rate-regulated electric revenues
—

 
2,856

 
1,189

 
1,118

 
2,086

 
—

 
(27
)
 
7,222

Rate-regulated natural gas revenues
—

 
—

 
304

 
436

 
94

 
—

 
(2
)
 
832

Shared service and other revenues
—

 
—

 
—

 
—

 
7

 
953

 
(959
)
 
1

Total operating revenues
$
8,613

 
$
2,856

 
$
1,493

 
$
1,554

 
$
2,187

 
$
953

 
$
(1,587
)
 
$
16,069

2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Competitive businesses electric revenues
$
8,052

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(565
)
 
$
7,487

Competitive businesses natural gas revenues
1,214

 
—

 
—

 
—

 
—

 
—

 
(1
)
 
1,213

Competitive businesses other revenues
240

 
—

 
—

 
—

 
—

 
—

 
(2
)
 
238

Rate-regulated electric revenues
—

 
2,759

 
1,185

 
1,198

 
2,218

 
—

 
(17
)
 
7,343

Rate-regulated natural gas revenues
—

 
—

 
369

 
427

 
95

 
—

 
(8
)
 
883

Shared service and other revenues
—

 
—

 
—

 
—

 
6

 
940

 
(944
)
 
2

Total operating revenues
$
9,506

 
$
2,759

 
$
1,554

 
$
1,625

 
$
2,319

 
$
940

 
$
(1,537
)
 
$
17,166

Intersegment revenues(c):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
601

 
$
16

 
$
4

 
$
10

 
$
7

 
$
949

 
$
(1,585
)
 
$
2

2019
568

 
9

 
3

 
12

 
7

 
935

 
(1,534
)
 
—

Depreciation and amortization:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
604

 
$
547

 
$
173

 
$
272

 
$
385

 
$
42

 
$
—

 
$
2,023

2019
814

 
508

 
164

 
252

 
369

 
47

 
—

 
2,154

Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
7,947

 
$
2,497

 
$
1,242

 
$
1,263

 
$
1,955

 
$
958

 
$
(1,564
)
 
$
14,298

2019
9,059

 
2,174

 
1,187

 
1,325

 
1,981

 
942

 
(1,526
)
 
15,142

Interest expense, net:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
197

 
$
192

 
$
71

 
$
64

 
$
134

 
$
179

 
$
—

 
$
837

2019
227

 
178

 
67

 
58

 
131

 
152

 
—

 
813


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

Note 4 — Segment Information

 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Other(a)
 
Intersegment
Eliminations
 
Exelon
Income (loss) before income taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
313

 
$
189

 
$
187

 
$
237

 
$
126

 
$
(175
)
 
$
2

 
$
879

2019
854

 
429

 
307

 
253

 
234

 
(151
)
 
—

 
1,926

Income Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
(59
)
 
$
82

 
$
9

 
$
18

 
$
(76
)
 
$
(49
)
 
$
—

 
$
(75
)
2019
301

 
85

 
37

 
47

 
11

 
(27
)
 
—

 
454

Net income (loss):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
368

 
$
107

 
$
178

 
$
219

 
$
202

 
$
(126
)
 
$
2

 
$
950

2019
540

 
344

 
270

 
206

 
223

 
(123
)
 
—

 
1,460

Capital Expenditures
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020
$
930

 
$
1,029

 
$
512

 
$
548

 
$
686

 
$
68

 
$
—

 
$
3,773

2019
890

 
961

 
447

 
542

 
698

 
34

 
—

 
3,572

Total assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
June 30, 2020
$
47,003

 
$
33,896

 
$
12,120

 
$
11,027

 
$
23,004

 
$
9,288

 
$
(10,025
)
 
$
126,313

December 31, 2019
48,995

 
32,765

 
11,469

 
10,634

 
22,719

 
8,484

 
(10,089
)
 
124,977

__________
(a)
Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(b)
Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(c)
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. See Note 18 — Related Party Transactions for additional information on intersegment revenues.


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

Note 4 — Segment Information

PHI:
 
Pepco
 
DPL
 
ACE
 
Other(a)
 
Intersegment
Eliminations
 
PHI
Operating revenues(b):
 
 
 
 
 
 
 
 
 
 
 
2020
 
 
 
 
 
 
 
 
 
 
 
Rate-regulated electric revenues
$
1,039

 
$
523

 
$
532

 
$
—

 
$
(8
)
 
$
2,086

Rate-regulated natural gas revenues
—

 
94

 
—

 
—

 
—

 
94

Shared service and other revenues
—

 
—

 
—

 
189

 
(182
)
 
7

Total operating revenues
$
1,039

 
$
617

 
$
532

 
$
189

 
$
(190
)
 
$
2,187

2019
 
 
 
 
 
 
 
 
 
 
 
Rate-regulated electric revenues
$
1,106

 
$
572

 
$
547

 
$
—

 
$
(7
)
 
$
2,218

Rate-regulated natural gas revenues
—

 
95

 
—

 
—

 
—

 
95

Shared service and other revenues
—

 
—

 
—

 
205

 
(199
)
 
6

Total operating revenues
$
1,106

 
$
667

 
$
547

 
$
205

 
$
(206
)
 
$
2,319

Intersegment revenues(c):
 
 
 
 
 
 
 
 
 
 
 
2020
$
3

 
$
4

 
$
1

 
$
189

 
$
(190
)
 
$
7

2019
3

 
3

 
1

 
205

 
(205
)
 
7

Depreciation and amortization:
 
 
 
 
 
 
 
 
 
 
 
2020
$
186

 
$
94

 
$
86

 
$
19

 
$
—

 
$
385

2019
186

 
91

 
71

 
20

 
1

 
369

Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
2020
$
899

 
$
547

 
$
509

 
$
190

 
$
(190
)
 
$
1,955

2019
929

 
550

 
498

 
208

 
(204
)
 
1,981

Interest expense, net:
 
 
 
 
 
 
 
 
 
 
 
2020
$
68

 
$
31

 
$
29

 
$
6

 
$
—

 
$
134

2019
68

 
30

 
28

 
5

 
—

 
131

Income (loss) before income taxes:
 
 
 
 
 
 
 
 
 
 
 
2020
$
90

 
$
44

 
$
(1
)
 
$
(7
)
 
$
—

 
$
126

2019(d)
123

 
94

 
25

 
(8
)
 
—

 
234

Income Taxes:
 
 
 
 
 
 
 
 
 
 
 
2020
$
(19
)
 
$
(20
)
 
$
(32
)
 
$
(5
)
 
$
—

 
$
(76
)
2019
4

 
11

 
1

 
(5
)
 
—

 
11

Net income (loss):
 
 
 
 
 
 
 
 
 
 
 
2020
$
109

 
$
64

 
$
31

 
$
(2
)
 
$
—

 
$
202

2019
119

 
83

 
24

 
(3
)
 
—

 
223

Capital Expenditures
 
 
 
 
 
 
 
 
 
 
 
2020
$
324

 
$
184

 
$
178

 
$
—

 
$
—

 
$
686

2019
298

 
160

 
227

 
13

 
—

 
698

Total assets:
 
 
 
 
 
 
 
 
 
 
 
June 30, 2020
$
8,869

 
$
4,966

 
$
4,089

 
$
5,234

 
$
(154
)
 
$
23,004

December 31, 2019(d)
8,661

 
4,830

 
3,933

 
5,335

 
(40
)
 
22,719


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

Note 4 — Segment Information

__________
(a)
Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
(b)
Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(c)
Includes intersegment revenues with ComEd, BGE and PECO, which are eliminated at Exelon.
(d)
The Income (loss) before income taxes and Total assets amounts in Other and Intersegment Eliminations have been adjusted by an offsetting $227 million and $5.7 billion, respectively, for consistency with the Exelon consolidating disclosure above.
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
 
Six Months Ended June 30, 2020
 
Revenues from external customers(a)
 
Intersegment
Revenues
 
Total
Revenues
 
Contracts with customers
 
Other(b)
 
Total
 
 
Mid-Atlantic
$
2,365

 
$
(133
)
 
$
2,232

 
$
15

 
$
2,247

Midwest
1,798

 
172

 
1,970

 
(6
)
 
1,964

New York
672

 
(16
)
 
656

 
(1
)
 
655

ERCOT
330

 
81

 
411

 
13

 
424

Other Power Regions
1,782

 
114

 
1,896

 
(21
)
 
1,875

Total Competitive Businesses Electric Revenues
6,947

 
218

 
7,165

 
—

 
7,165

Competitive Businesses Natural Gas Revenues
712

 
313

 
1,025

 
—

 
1,025

Competitive Businesses Other Revenues(c)
185

 
238

 
423

 
—

 
423

Total Generation Consolidated Operating Revenues
$
7,844

 
$
769

 
$
8,613

 
$
—

 
$
8,613

 
Six Months Ended June 30, 2019
 
Revenues from external customers(a)
 
Intersegment
revenues
 
Total
Revenues
 
Contracts with customers
 
Other(b)
 
Total
 
 
Mid-Atlantic
$
2,448

 
$
(2
)
 
$
2,446

 
$
(1
)
 
$
2,445

Midwest
2,030

 
126

 
2,156

 
(14
)
 
2,142

New York
781

 
1

 
782

 
—

 
782

ERCOT
307

 
126

 
433

 
8

 
441

Other Power Regions
1,976

 
259

 
2,235

 
(21
)
 
2,214

Total Competitive Businesses Electric Revenues
7,542

 
510

 
8,052

 
(28
)
 
8,024

Competitive Businesses Natural Gas Revenues
763

 
451

 
1,214

 
28

 
1,242

Competitive Businesses Other Revenues(c)
230

 
10

 
240

 
—

 
240

Total Generation Consolidated Operating Revenues
$
8,535

 
$
971

 
$
9,506

 
$
—

 
$
9,506


__________

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

Note 4 — Segment Information

(a)
Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)
Includes revenues from derivatives and leases.
(c)
Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $200 million and losses of $14 million in 2020 and 2019, respectively, and elimination of intersegment revenues.

Revenues net of purchased power and fuel expense (Generation):
 
Six Months Ended June 30, 2020
 
Six Months Ended June 30, 2019
 
RNF
from external
customers(a)
 
Intersegment
RNF
 
Total RNF
 
RNF
from external
customers(a)
 
Intersegment
RNF
 
Total RNF
Mid-Atlantic
$
1,074

 
$
18

 
$
1,092

 
$
1,324

 
$
10

 
$
1,334

Midwest
1,431

 
(4
)
 
1,427

 
1,506

 
(6
)
 
1,500

New York
433

 
7

 
440

 
512

 
7

 
519

ERCOT
168

 
9

 
177

 
178

 
(24
)
 
154

Other Power Regions
355

 
(43
)
 
312

 
328

 
(36
)
 
292

Total Revenues net of purchased power and fuel expense for Reportable Segments
3,461


(13
)

3,448


3,848


(49
)

3,799

Other(b)
506

 
13

 
519

 
161

 
49

 
210

Total Generation Revenues net of purchased power and fuel expense
$
3,967


$
—


$
3,967


$
4,009


$
—


$
4,009


__________
(a)
Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)
Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $218 million and losses of $102 million in 2020 and 2019, respectively and the elimination of intersegment RNF.



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

Note 4 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):
 
Six Months Ended June 30, 2020
Revenues from contracts with customers
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Rate-regulated electric revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
1,468

 
$
759

 
$
644

 
$
1,062

 
$
472

 
$
308

 
$
282

Small commercial & industrial
689

 
187

 
118

 
221

 
65

 
82

 
74

Large commercial & industrial
253

 
108

 
198

 
493

 
363

 
45

 
85

Public authorities & electric railroads
23

 
14

 
14

 
31

 
17

 
6

 
7

Other(a)
430

 
113

 
154

 
332

 
119

 
105

 
109

Total rate-regulated electric revenues(b)
$
2,863

 
$
1,181

 
$
1,128

 
$
2,139

 
$
1,036

 
$
546

 
$
557

Rate-regulated natural gas revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
—

 
$
220

 
$
287

 
$
57

 
$
—

 
$
57

 
$
—

Small commercial & industrial
—

 
70

 
46

 
25

 
—

 
25

 
—

Large commercial & industrial
—

 
—

 
76

 
2

 
—

 
2

 
—

Transportation
—

 
12

 
—

 
7

 
—

 
7

 
—

Other(c)
—

 
2

 
13

 
3

 
—

 
3

 
—

Total rate-regulated natural gas revenues(d)
$
—

 
$
304

 
$
422

 
$
94

 
$
—

 
$
94

 
$
—

Total rate-regulated revenues from contracts with customers
$
2,863

 
$
1,485

 
$
1,550

 
$
2,233

 
$
1,036

 
$
640

 
$
557

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from alternative revenue programs
$
(13
)
 
$
5

 
$
—

 
$
(47
)
 
$
2

 
$
(24
)
 
$
(25
)
Other rate-regulated electric revenues(e)
6

 
3

 
3

 
1

 
1

 
1

 
—

Other rate-regulated natural gas revenues(e)
—

 
—

 
1

 
—

 
—

 
—

 
—

Total other revenues
$
(7
)
 
$
8

 
$
4

 
$
(46
)
 
$
3

 
$
(23
)
 
$
(25
)
Total rate-regulated revenues for reportable segments
$
2,856

 
$
1,493

 
$
1,554

 
$
2,187

 
$
1,039

 
$
617

 
$
532



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

Note 4 — Segment Information

 
Six Months Ended June 30, 2019
Revenues from contracts with customers
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Rate-regulated electric revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
1,356

 
$
752

 
$
667

 
$
1,073

 
$
480

 
$
320

 
$
273

Small commercial & industrial
709

 
195

 
129

 
241

 
73

 
93

 
75

Large commercial & industrial
259

 
100

 
219

 
545

 
411

 
49

 
85

Public authorities & electric railroads
23

 
14

 
13

 
31

 
17

 
7

 
7

Other(a)
442

 
123

 
160

 
317

 
108

 
101

 
108

Total rate-regulated electric revenues(b)
$
2,789

 
$
1,184

 
$
1,188

 
$
2,207

 
$
1,089

 
$
570

 
$
548

Rate-regulated natural gas revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
—

 
$
247

 
$
279

 
$
55

 
$
—

 
$
55

 
$
—

Small commercial & industrial
—

 
105

 
46

 
26

 
—

 
26

 
—

Large commercial & industrial
—

 
1

 
73

 
3

 
—

 
3

 
—

Transportation
—

 
13

 
—

 
7

 
—

 
7

 
—

Other(c)
—

 
3

 
13

 
4

 
—

 
4

 
—

Total rate-regulated natural gas revenues(d)
$
—

 
$
369

 
$
411

 
$
95

 
$
—

 
$
95

 
$
—

Total rate-regulated revenues from contracts with customers
$
2,789

 
$
1,553

 
$
1,599

 
$
2,302

 
$
1,089

 
$
665

 
$
548

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from alternative revenue programs
$
(42
)
 
$
(6
)
 
$
17

 
$
12

 
$
13

 
$
1

 
$
(1
)
Other rate-regulated electric revenues(e)
12

 
7

 
6

 
5

 
4

 
1

 
—

Other rate-regulated natural gas revenues(e)
—

 
—

 
3

 
—

 
—

 
—

 
—

Total other revenues
$
(30
)
 
$
1

 
$
26

 
$
17

 
$
17

 
$
2

 
$
(1
)
Total rate-regulated revenues for reportable segments
$
2,759

 
$
1,554

 
$
1,625

 
$
2,319

 
$
1,106

 
$
667

 
$
547


__________
(a)
Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)
Includes operating revenues from affiliates of $16 million, $3 million, $6 million, $7 million, $3 million, $4 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2020 and $9 million, $2 million, $1 million, $7 million, $3 million, $3 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019.
(c)
Includes revenues from off-system natural gas sales.
(d)
Includes operating revenues from affiliates of less than $1 million and $4 million at PECO and BGE, respectively, in 2020 and $1 million and $9 million at PECO and BGE, respectively, in 2019.
(e)
Includes late payment charge revenues.


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

Note 5 — Accounts Receivable

5. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable (All Registrants)
The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.
 
Three Months Ended June 30, 2020
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Balance as of March 31, 2020
$
278

 
$
81

 
$
71

 
$
66

 
$
18

 
$
42

 
$
15

 
$
13

 
$
14

Plus: Current Period Provision for Expected Credit Losses
51

 
9

 
7

 
10

 
6

 
19

 
8

 
5

 
6

Less: Write-offs, net of recoveries(a)
12

 
1

 
6

 
5

 
1

 
(1
)
 
(1
)
 
—

 
—

Less: Sale of customer accounts receivable (b)
56

 
56

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Balance as of June 30, 2020
$
261

 
$
33

 
$
72

 
$
71

 
$
23

 
$
62

 
$
24

 
$
18

 
$
20

 
Six Months Ended June 30, 2020
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Balance as of December 31, 2019
$
243

 
$
80

 
$
59

 
$
55

 
$
12

 
$
37

 
$
13

 
$
11

 
$
13

Plus: Current Period Provision for Expected Credit Losses
106

 
13

 
25

 
28

 
14

 
26

 
11

 
7

 
8

Less: Write-offs, net of recoveries(a)
32

 
4

 
12

 
12

 
3

 
1

 
—

 
—

 
1

Less: Sale of customer accounts receivable (b)

56

 
56

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Balance as of June 30, 2020
$
261

 
$
33

 
$
72

 
$
71

 
$
23

 
$
62

 
$
24

 
$
18

 
$
20

_________
(a)
Recoveries were not material to the Registrants.
(b)
See below for additional information on the sale of customer accounts receivable at Generation in the second quarter of 2020.


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

Note 5 — Accounts Receivable

The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
 
Three Months Ended June 30, 2020
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Balance as of March 31, 2020
$
52

 
$
—

 
$
22

 
$
7

 
$
5

 
$
18

 
$
8

 
$
4

 
$
6

Plus: Current Period Provision for Expected Credit Losses
12

 
—

 
1

 
1

 
2

 
8

 
3

 
3

 
2

Less: Write-offs, net of recoveries(a)
3

 
—

 
1

 
1

 
1

 
—

 
—

 
—

 
—

Balance as of June 30, 2020
$
61

 
$
—

 
$
22

 
$
7

 
$
6

 
$
26

 
$
11

 
$
7

 
$
8


 
Six Months Ended June 30, 2020
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Balance as of December 31, 2019
$
48

 
$
—

 
$
20

 
$
7

 
$
5

 
$
16

 
$
7

 
$
4

 
$
5

Plus: Current Period Provision for Expected Credit Losses
20

 
—

 
4

 
2

 
4

 
10

 
4

 
3

 
3

Less: Write-offs, net of recoveries(a)
7

 
—

 
2

 
2

 
3

 
—

 
—

 
—

 
—

Balance as of June 30, 2020
$
61

 
$
—

 
$
22

 
$
7

 
$
6

 
$
26

 
$
11

 
$
7

 
$
8

_________
(a)
Recoveries were not material to the Registrants.

Unbilled Customer Revenue (All Registrants)
The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets.
 
Unbilled customer revenues(a)
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
June 30, 2020
$
804

 
$
120

 
$
257

 
$
120

 
$
116

 
$
191

 
$
102

 
$
49

 
$
40

December 31, 2019
1,535

 
807

 
218

 
146

 
170

 
194

 
100

 
61

 
33

_________
(a)
Unbilled customer revenues are classified in customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.
Sales of Customer Accounts Receivable (Exelon and Generation)
On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly-owned by Generation, entered into a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (the Purchasers) to sell certain customer accounts receivable (the Facility). The Facility, whose maximum capacity is $750 million, is scheduled to expire on April 7, 2021, unless renewed by the mutual consent of the parties in accordance with its terms. Under the Facility, NER may sell eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers are reported as sales of receivables in Exelon’s and Generation’s consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the DPP, which is reflected in Other current assets on Exelon’s and Generation’s Consolidated Balance Sheet.

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

Note 5 — Accounts Receivable

On April 8, 2020, Generation derecognized and transferred approximately $1.2 billion of receivables at fair value to the Purchasers in exchange for approximately $500 million in cash purchase price and $650 million of DPP.
The following table summarizes the impact of the sale of certain receivables:
 
As of June 30, 2020
Derecognized receivables transferred at fair value(a)
$
1,135

Cash proceeds received
500

DPP
635

_________
(a)
Includes additional customer accounts receivable sold into the Facility of $2,032 million since the start of the financing agreement.

 
Three and six months ended June 30, 2020
Loss on sale of receivables(a)

$
15

_________
(a)
Reflected in Operating and maintenance expense on Exelon and Generation's Consolidated Statements of Operations and Income Statement.

 
Six months ended June 30, 2020
Proceeds from new transfers
$
927

Cash collections received on DPP
1,102

Cash collections reinvested in the Facility
2,029


Generation’s risk of loss following the transfer of accounts receivable is limited to the DPP outstanding.  Payment of DPP is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred, which have historically been and are expected to be immaterial. Generation continues to service the receivables sold in exchange for a servicing fee. Generation did not record a servicing asset or liability as the servicing fees were immaterial.
Generation reflected the cash proceeds received upon sale in Net cash provided by operating activities in the Consolidated Statements of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities of the Consolidated Statements of Cash Flows.
See Note 13 — Fair Value of Financial Assets and Liabilities and Note 16 — Variable Interest Entities for additional information.
Other Purchases and Sales of Customer and Other Accounts Receivables (All Registrants)
Generation is required, under supplier tariffs in ISO-NE, MISO, NYISO and PJM, to sell customer and other receivables to utility companies, which include the Utility Registrants. 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. The following tables present the total receivables purchased and sold.

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

Note 5 — Accounts Receivable

 
Six Months Ended June 30, 2020
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Total Receivables Purchased
$
1,584

 
$
—

 
$
518

 
$
494

 
$
333

 
$
485

 
$
303

 
$
98

 
$
84

Total Receivables Sold
533

 
779

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Related Party Transactions:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Receivables purchased from Generation
—

 
—

 
34

 
67

 
73

 
72

 
51

 
13

 
8

Receivables sold to the Utility Registrants
—

 
246

 
—

 
—

 
—

 
—

 
—

 
—

 
—


6. Early Plant Retirements (Exelon and Generation)
Exelon and Generation continuously evaluate factors that affect the current and expected economic value of Generation’s plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, just prior to its next scheduled nuclear refueling outage.
Nuclear Generation
In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York and Three Mile Island nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision-making authority to retire Salem.
Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program and the New York CES, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Salem, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent the Illinois ZES, New Jersey ZEC program or the New York CES do not operate as expected over their full terms, each of these plants could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. In addition, FERC’s December 19, 2019 order on the MOPR in PJM may undermine the continued effectiveness of the Illinois ZES and the New Jersey ZEC program unless Illinois and New Jersey implement an FRR mechanism under which the Generation plants in these states would be removed from PJM’s capacity auction. See Note 2 — Regulatory Matters for additional information on the New Jersey ZEC program, New York CES and FERC's December 19, 2019 order and Note 3 — Regulatory Matters of the 2019 Form 10-K for additional information on the Illinois ZES.
In Pennsylvania, the TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Generation announced that it would permanently cease generation operations at TMI. On September 20, 2019, Generation permanently ceased generation operations at TMI.

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

Note 6 — Early Plant Retirements

As a result of the early nuclear plant retirement decision at TMI, Exelon and Generation recognized incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel, as well as operating and maintenance expenses. The total impact for the three and six months ended June 30, 2019 are summarized in the table below.
Income statement expense (pre-tax)
 
Three Months Ended June 30, 2019
 
Six Months Ended June 30, 2019
Depreciation and amortization
 
 
 
 
Accelerated depreciation
 
$
71

 
$
145

Accelerated nuclear fuel amortization
 
4

 
9

Operating and maintenance(a)
 
—

 
(83
)
Total
 
$
75

 
$
71

_________
(a)
Primarily reflects the net impacts associated with the remeasurement of the TMI ARO. See Note 9 — Asset Retirement Obligations of the 2019 Form 10-K for additional information.
Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. While all of LaSalle's capacity did clear in the 2021-2022 planning year auction, Generation has become increasingly concerned about the economic viability of this plant as well in a landscape where energy market prices remain depressed and energy market rules remain fatally flawed. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level. The absence of such solutions or reforms could result in future impairments of the Midwest asset group, or accelerated depreciation for specific plants over their shortened estimated useful lives, both of which could have a material unfavorable impact on Exelon's and Generation's future results of operations.
The following table provides the balance sheet amounts as of June 30, 2020 for Exelon's and Generation's significant assets and liabilities associated with these four nuclear plants. Depreciation provisions are based on the estimated useful lives of these nuclear generating stations, which reflect the first renewal of the operating licenses.
 
 
Dresden
 
Byron
 
Braidwood
 
LaSalle
 
Total
Asset Balances
 
 
 
 
 
 
 
 
 
 
Materials and supplies inventory, net
 
$
70

 
$
70

 
$
82

 
$
108

 
$
330

Nuclear fuel inventory, net
 
182

 
145

 
180

 
244

 
751

Completed plant, net
 
1,057

 
1,334

 
1,416

 
1,588

 
5,395

Construction work in progress
 
18

 
21

 
18

 
19

 
76

Liability Balances
 
 
 
 
 
 
 
 
 
 
Asset retirement obligation
 
(1,317
)
 
(604
)
 
(562
)
 
(915
)
 
(3,398
)
 
 
 
 
 
 
 
 
 
 
 
NRC License First Renewal Term
 
2029 (Unit 2)

 
2044 (Unit 1)

 
2046 (Unit 1)

 
2042 (Unit 1)

 
 
 
2031 (Unit 3)

 
2046 (Unit 2)

 
2047 (Unit 2)

 
2043 (Unit 2)

 
 

Other Generation
On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022, at the end of the then-current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 was then committed through May 2021.

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

Note 6 — Early Plant Retirements

On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service agreement, reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. Those adjustments were reflected in a compliance filing filed March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings in the order. On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the Everett Marine Terminal. FERC directed a downward adjustment to the rate base for Mystic Units 8 and 9, the effect of which will be partially offset by elimination of a crediting mechanism for third party gas sales during the term of the cost of service agreement. A compliance filing will be due on September 15, 2020. On July 28, 2020, FERC ordered additional briefings in the ROE proceeding, with initial briefs due by September 28, 2020.
On March 25, 2019, ISO-NE filed the Inventoried Energy Program (IEP), which is intended to provide an interim fuel security program pending conclusion of the stakeholder process to develop a long-term, market-based solution to address fuel security. The IEP went into effect by operation of law on August 5, 2019 because FERC did not have a quorum at that time. On October 7, 2019, requests for rehearing were denied and several parties appealed to the D.C. Circuit Court. On April 14, 2020, FERC filed an unopposed motion asking the court for a voluntary remand of the IEP order, noting that FERC now has a quorum of commissioners who can participate in the consideration of ISO-NE’s IEP filing. On April 21, 2020, the D.C. Circuit Court granted the voluntary remand and on June 18, 2020, FERC issued an order finding the IEP just and reasonable and accepting ISO-NE's proposed tariff revisions. Several parties have filed requests for rehearing.
On April 15, 2020, ISO-NE filed its long-term, market-based fuel security proposal, proposing three new, day-ahead ancillary services products intended to compensate generators for operational capabilities that provide fuel security to the region. In the filing, ISO-NE also proposed to sunset the Fuel Security Retention Mechanism, through which Mystic has been retained for fuel security, and the IEP by June 1, 2024. In addition, the filing includes an alternate proposal sponsored by New England Power Pool (NEPOOL), which includes substantive amendments to the ISO-NE proposal. On May 15, 2020, Exelon filed a limited protest to ISO's long-term fuel-security proposal asking FERC to accept ISO-NE's proposal but to direct ISO-NE to revise its tariff so that the IEP remains in place as a safeguard until the long-term solution is in place. A number of other comments in support and protests have been filed. ISO-NE asked for a decision on its proposal by November 1, 2020.
On June 12, 2020, Generation filed a complaint with FERC against ISO-NE on the grounds that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic for transmission security for the 2024 to 2025 Capacity Commitment Period (FCA 15) and that modifications ISO-NE made to its unfiled planning procedures to avoid retaining Mystic should have been filed with FERC for approval. Generation asked for a ruling from FERC by August 10, 2020, but ISO-NE asserts that a ruling is not needed until November 2, 2020. On July 27, 2020, ISO-NE issued a memo to NEPOOL announcing its determination pursuant to its unfiled planning procedures that Mystic Units 8 and 9 are not needed for FCA 15 for transmission security. It had previously determined Mystic Units 8 and 9 are not needed for fuel security. The timing and the outcome of this proceeding is uncertain.
The following table provides the balance sheet amounts as of June 30, 2020 for Exelon's and Generation’s significant assets and liabilities associated with the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by the failure to adopt long-term solutions for reliability and fuel security.
 
 
June 30, 2020
Asset Balances
 
 
Materials and supplies inventory
 
$
33

Fuel inventory
 
6

Property, plant and equipment, net
 
898

Liability Balances
 
 
Asset retirement obligation
 
(3
)

See Note 8 — Asset Impairments for impairment assessment considerations on the New England Asset Group.

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

Note 7 — Nuclear Decommissioning

7. Nuclear Decommissioning (Exelon and Generation)
Nuclear Decommissioning Asset Retirement Obligations
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.
The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC within Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2019 to June 30, 2020:
Nuclear decommissioning ARO at December 31, 2019 (a)
$
10,504

Accretion expense
243

Costs incurred related to decommissioning plants
$
(37
)
Nuclear decommissioning ARO at June 30, 2020 (a)
$
10,710

_________
(a)
Includes $104 million and $112 million as the current portion of the ARO at June 30, 2020 and December 31, 2019, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

NDT Funds
Exelon and Generation had NDT funds totaling $12,917 million and $13,353 million at June 30, 2020 and December 31, 2019, respectively. The NDT funds also include $187 million and $163 million for the current portion of the NDT funds at June 30, 2020 and December 31, 2019, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 17 — Supplemental Financial Information for additional information on activities of the NDT funds.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.
Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for all units, including its shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the April 1, 2019 submittal. On March 31, 2020, Generation filed its annual decommissioning funding status report with the NRC for Generation’s shutdown units (excluding Zion Station for the reason noted above). The annual status report demonstrated adequate decommissioning funding assurance as of December 31, 2019, for all of its shutdown reactors 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, collections from PECO ratepayers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff.  See Note 9 — Asset Retirement

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

Note 7 — Nuclear Decommissioning

Obligations of the Exelon 2019 Form 10-K for information regarding the amount collected from PECO ratepayers for decommissioning cost.
8. Asset Impairments (Exelon and Generation)
The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.
Antelope Valley Solar Facility
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of June 30, 2020, Generation had approximately $710 million of net long-lived assets related to Antelope Valley. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and no impairment charge was recorded.
Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,840 million of additional net long-lived assets as of June 30, 2020. 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.
The United States Bankruptcy Court entered an order on June 20, 2020 confirming PG&E’s plan of reorganization. On July 1, 2020 the plan became effective, and PG&E emerged from bankruptcy. Under the confirmed plan, PG&E will continue to honor the existing PPA agreement with Antelope Valley.
See Note 12 - Debt and Credit Agreements for additional information.
New England Asset Group
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 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. In the second quarter of 2018, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and no impairment charge was required. Generation continues to monitor developments in the region that would indicate a potential triggering event for impairment and continues to look for solutions that appropriately compensate both Mystic 8 and 9 and the Everett Marine Terminal for their contributions to the region. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in material future impairments of the New England asset group. See Note 6 - Early Plant Retirements for additional information.
Midwest Asset Group
We continue to monitor the recoverability of the carrying value of the Midwest asset group as certain nuclear plants in Illinois are showing increased signs of economic distress, which could lead to an early retirement. See Note 6 - Early Plant Retirements for additional information.

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

Note 9 — Income Taxes

9. Income Taxes (All Registrants)
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:
 
Three Months Ended June 30, 2020
 
Exelon(a)

Generation(a)

ComEd(b)

PECO(c)

BGE(c)
 
PHI(c)
 
Pepco(c)
 
DPL(d)
 
ACE(d)
U.S. Federal statutory rate
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
3.8
 
3.1
 
(131.7)
 
(9.7)
 
3.8
 
(25.8)
 
2.1
 
6.7
 
7.2
Qualified NDT fund income
18.8
 
17.3
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Deferred Prosecution Agreement payments
5.3
 
—
 
(288.3)
 
—
 
—
 
—
 
—
 
—
 
—
Amortization of investment tax credit, including deferred taxes on basis difference
(0.6)
 
(0.5)
 
2.9
 
—
 
(0.2)
 
(2.2)
 
(0.1)
 
0.5
 
0.3
Plant basis differences
(1.6)
 
—
 
2.4
 
(23.6)
 
(13.4)
 
(44.7)
 
(3.9)
 
(1.1)
 
10.0
Production tax credits and other credits
(1.4)
 
(1.2)
 
3.3
 
—
 
(1.0)
 
(0.7)
 
(0.1)
 
0.1
 
—
Noncontrolling interests
0.1
 
0.1
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Excess deferred tax amortization
(15.5)
 
—
 
116.0
 
(4.8)
 
(137.9)
 
(1,358.5)
 
(89.0)
 
284.0
 
174.5
Tax Settlements
(1.9)
 
(1.8)
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Other
(0.4)
 
0.3
 
(32.3)
 
(4.8)
 
(1.7)
 
168.0
 
(2.7)
 
(0.1)
 
7.0
Effective income tax rate
27.6%
 
38.3%
 
(306.7)%
 
(21.9)%
 
(129.4)%
 
(1,242.9)%
 
(72.7)%
 
311.1%
 
220.0%
_________
(a)
At Exelon and Generation, positive percentages represent income tax expense.
(b)
ComEd recognized a loss before income taxes for the three months ended June 30, 2020. As a result, negative percentages represent income tax expense. The higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 14 — Commitments and Contingencies for additional information.
(c)
At PECO, BGE, PHI, and Pepco, negative percentages represent an income tax benefit. At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm repairs. At BGE, PHI, and Pepco, the lower effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 2 — Regulatory Matters for additional information.
(d)
DPL and ACE recognized a loss before income taxes for the three months ended June 30, 2020. As a result, positive percentages represent an income tax benefit. At DPL and ACE, the higher effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 2 — Regulatory Matters for additional information.




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

Note 9 — Income Taxes

 
Three Months Ended June 30, 2019
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
U.S. Federal statutory rate
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
5.4
 
5.5
 
8.2
 
(1.2)
 
6.5
 
4.8
 
2.0
 
7.0
 
7.0
Qualified NDT fund income
5.1
 
16.2
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Amortization of investment tax credit, including deferred taxes on basis difference
(0.7)
 
(1.9)
 
(0.2)
 
—
 
(0.1)
 
(0.2)
 
(0.1)
 
(0.2)
 
(0.3)
Plant basis differences
(1.7)
 
—
 
(0.6)
 
(5.9)
 
(1.5)
 
(1.7)
 
(2.1)
 
(0.3)
 
(2.2)
Production tax credits and other credits
(0.9)
 
(2.8)
 
—
 
—
 
(0.1)
 
—
 
—
 
—
 
—
Noncontrolling interests
0.1
 
0.4
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Excess deferred tax amortization
(7.8)
 
—
 
(9.0)
 
(2.7)
 
(7.9)
 
(19.4)
 
(18.3)
 
(15.7)
 
(23.1)
Other
1.9
 
0.2
 
0.4
 
0.1
 
1.7
 
0.9
 
0.5
 
—
 
(2.4)
Effective income tax rate
22.4%
 
38.6%
 
19.8%
 
11.3%
 
19.6%
 
5.4%
 
3.0%
 
11.8%
 
—%



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

Note 9 — Income Taxes

 
Six Months Ended June 30, 2020
 
Exelon
 
Generation(a)
 
ComEd(b)
 
PECO(c)
 
BGE(d)
 
PHI(d)
 
Pepco(d)
 
DPL(d)
 
ACE(e)
U.S. Federal statutory rate
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
6.7
 
7.2
 
19.1
 
(1.6)
 
5.6
 
4.3
 
3.7
 
6.5
 
12.4
Qualified NDT fund income
(5.7)
 
(16.0)
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Deferred Prosecution Agreement payments
4.8
 
—
 
22.2
 
—
 
—
 
—
 
—
 
—
 
—
Amortization of investment tax credit, including deferred taxes on basis difference
(1.0)
 
(2.3)
 
(0.4)
 
—
 
(0.1)
 
(0.2)
 
(0.1)
 
(0.3)
 
7.2
Plant basis differences
(3.7)
 
—
 
(1.4)
 
(11.0)
 
(2.0)
 
(3.5)
 
(2.7)
 
(0.6)
 
146.2
Production tax credits and other credits
(2.2)
 
(5.5)
 
(0.4)
 
—
 
(0.2)
 
(0.1)
 
(0.1)
 
—
 
0.7
Noncontrolling interests
1.1
 
3.2
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Excess deferred tax amortization
(20.9)
 
—
 
(20.2)
 
(3.3)
 
(16.1)
 
(80.3)
 
(41.6)
 
(72.9)
 
2,613.8
Tax Settlements
(9.3)
 
(26.1)
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Other
0.7
 
(0.3)
 
3.5
 
(0.3)
 
(0.6)
 
(1.5)
 
(1.3)
 
0.8
 
398.7
Effective income tax rate
(8.5)%
 
(18.8)%
 
43.4%
 
4.8%
 
7.6%
 
(60.3)%
 
(21.1)%
 
(45.5)%
 
3,200.0%
_________
(a)
At Generation, the lower effective tax rate is primarily attributable to tax settlements.
(b)
At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 14 — Commitments and Contingencies for additional information.
(c)
At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm repairs.
(d)
At BGE, PHI, Pepco, and DPL, the lower effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 2 — Regulatory Matters for additional information.
(e)
ACE recognized a loss before income taxes for the six months ended June 30, 2020. As a result, a positive percentage at ACE represents an income tax benefit for the period presented. At ACE, the higher effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 2 — Regulatory Matters for additional information.




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

Note 9 — Income Taxes

 
Six Months Ended June 30, 2019
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
U.S. Federal statutory rate
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
4.4
 
3.6
 
8.2
 
0.2
 
6.4
 
4.7
 
2.0
 
6.7
 
6.9
Qualified NDT fund income
6.5
 
14.7
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Amortization of investment tax credit, including deferred taxes on basis difference
(0.6)
 
(1.1)
 
(0.2)
 
—
 
(0.1)
 
(0.2)
 
(0.1)
 
(0.2)
 
(0.3)
Plant basis differences
(1.5)
 
—
 
(0.6)
 
(6.4)
 
(1.0)
 
(1.7)
 
(2.0)
 
(0.6)
 
(2.2)
Production tax credits and other credits
(0.8)
 
(1.8)
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Noncontrolling interests
(0.3)
 
(0.8)
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Excess deferred tax amortization
(5.8)
 
—
 
(8.8)
 
(2.6)
 
(7.9)
 
(19.4)
 
(18.1)
 
(15.6)
 
(23.4)
Other
0.7
 
(0.4)
 
0.2
 
(0.1)
 
0.2
 
0.3
 
0.5
 
0.4
 
2.0
Effective income tax rate
23.6%
 
35.2%
 
19.8%
 
12.1%
 
18.6%
 
4.7%
 
3.3%
 
11.7%
 
4.0%



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

Note 9 — Income Taxes

Accounting for Uncertainty in Income Taxes
Exelon, Generation, PHI and ACE have the following unrecognized tax benefits as of June 30, 2020 and December 31, 2019. ComEd, PECO, BGE, Pepco and DPL's amounts are not material.
 
Exelon
 
Generation
 
PHI
 
ACE
June 30, 2020
$
122

 
$
49

 
$
50

 
$
15

December 31, 2019
507

 
441

 
48

 
14


Exelon's and Generation's unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase to Exelon's and Generation’s net income of $76 million and $73 million, respectively, in the first quarter of 2020, reflecting a decrease to Exelon's and Generation's income tax expense of $67 million.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
The following table represents Exelon's, PHI's and ACE's unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, and the outcomes of pending court cases as of June 30, 2020. Generation's, ComEd's, PECO's, BGE's, Pepco's and DPL's amounts are not material.
Exelon
 
PHI
 
ACE(a)
$
14

 
$
14

 
$
14

_________
(a)
The unrecognized tax benefit related to ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Other Income Tax Matters
State Income Tax Law Changes
On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation and ComEd do not expect a material impact to their financial statements as a result of the rate change.
10. Retirement Benefits (All Registrants)
Defined Benefit Pension and OPEB
During the first quarter of 2020, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2020. This valuation resulted in an increase to the pension and OPEB obligations of $8 million and $31 million, respectively. Additionally, accumulated other comprehensive loss increased by $7 million (after-tax) and regulatory assets and liabilities increased by $19 million and decreased by $10 million, respectively.
The majority of the 2020 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 3.34%. The majority of the 2020 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.69% for funded plans and a discount rate of 3.31%.

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

Note 10 — Retirement Benefits

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, 2020 and 2019.
 
Pension Benefits
Three Months Ended June 30,
 
OPEB
Three Months Ended June 30,
 
2020
 
2019
 
2020
 
2019
Components of net periodic benefit cost:
 
 
 
 
 
 
 
Service cost
$
96

 
$
89

 
$
22

 
$
24

Interest cost
190

 
221

 
39

 
47

Expected return on assets
(318
)
 
(306
)
 
(40
)
 
(38
)
Amortization of:
 
 
 
 
 
 
 
Prior service cost (benefit)
1

 
—

 
(31
)
 
(44
)
Actuarial loss
128

 
103

 
12

 
10

Settlement charges
6

 
—

 
—

 
—

Net periodic benefit cost
$
103

 
$
107

 
$
2

 
$
(1
)


Pension Benefits
Six Months Ended June 30,
 
OPEB
Six Months Ended June 30,
 
2020
 
2019
 
2020
 
2019
Components of net periodic benefit cost:


 


 


 


Service cost
$
193

 
$
178

 
$
45

 
$
47

Interest cost
379

 
442

 
77

 
94

Expected return on assets
(636
)
 
(612
)
 
(81
)
 
(77
)
Amortization of:
 
 
 
 
 
 
 
Prior service cost (benefit)
2

 
—

 
(62
)
 
(89
)
Actuarial loss
256

 
206

 
24

 
23

Settlement charges
6

 
—

 
—

 
—

Net periodic benefit cost
$
200


$
214


$
3


$
(2
)

The amounts below represent the Registrants' allocated pension and OPEB plan costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For Generation and the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant and equipment, net in their consolidated financial statements.
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Pension and OPEB Costs
 
2020
 
2019
 
2020
 
2019
Exelon
 
$
105

 
$
106

 
$
203

 
$
212

Generation
 
32

 
31

 
59

 
62

ComEd
 
28

 
23

 
57

 
47

PECO
 
1

 
3

 
3

 
5

BGE
 
16

 
16

 
31

 
30

PHI
 
18

 
24

 
35

 
48

Pepco
 
4

 
6

 
7

 
12

DPL
 
2

 
4

 
4

 
8

ACE
 
3

 
4

 
7

 
8



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

Note 10 — Retirement Benefits

Defined Contribution Savings Plans
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three and six months ended June 30, 2020 and 2019, respectively.
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Savings Plan Matching Contributions
 
2020
 
2019
 
2020
 
2019
Exelon
 
$
34

 
$
33


$
67


$
64

Generation
 
14

 
14

 
27

 
28

ComEd
 
9

 
9

 
16

 
16

PECO
 
2

 
2

 
5

 
5

BGE
 
2

 
2

 
4

 
4

PHI
 
3

 
3

 
6

 
6

Pepco
 
1

 
1

 
2

 
2

DPL
 
—

 
1

 
1

 
1

ACE
 
1

 
—

 
1

 
1


11. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, interest rate risk and foreign exchange risk related to ongoing business operations.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at Generation and are offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.
Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below that present fair value balances, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.
Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
Commodity Price Risk (All Registrants)
Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and commodity products.

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

Note 11 — Derivative Financial Instruments

The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.
Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.
Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
Registrant
Commodity
Accounting Treatment
Hedging instrument
ComEd
Electricity
NPNS
Fixed price contracts based on all requirements in the IPA procurement plans.
Electricity
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)
20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO(b)
Gas
NPNS
Fixed price contracts to cover about 20% of planned natural gas purchases in support of projected firm sales.
BGE
Electricity
NPNS
Fixed price contracts for all SOS requirements through full requirements contracts.
Gas
NPNS
Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
Pepco
Electricity
NPNS
Fixed price contracts for all SOS requirements through full requirements contracts.
DPL
Electricity
NPNS
Fixed price contracts for all SOS requirements through full requirements contracts.
Gas
NPNS
Fixed and Index priced contracts through full requirements contracts.
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(c)
Exchange traded future contracts for 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE
Electricity
NPNS
Fixed price contracts for all BGS requirements through full requirements contracts.
__________
(a)
See Note 3 - Regulatory Matters of the 2019 Form 10-K for additional information.
(b)
As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.
(c)
The fair value of the DPL economic hedge is not material as of June 30, 2020 and December 31, 2019 and is not presented in the fair value tables below.

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

Note 11 — Derivative Financial Instruments

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation and ComEd as of June 30, 2020 and December 31, 2019:
June 30, 2020
 
Exelon
 
Generation
 
ComEd
Derivatives
 
Total
Derivatives
 
Economic
Hedges
 
Proprietary
Trading
 
Collateral

 (a)(b)
 
Netting (a)
 
Subtotal
 
Economic
Hedges
Mark-to-market derivative assets
(current assets)
 
$
570

 
$
3,240

 
$
70

 
$
179

 
$
(2,919
)
 
$
570

 
$
—

Mark-to-market derivative assets
(noncurrent assets)
 
466

 
1,582

 
20

 
77

 
(1,213
)
 
466

 
—

Total mark-to-market derivative assets
 
1,036

 
4,822

 
90

 
256

 
(4,132
)
 
1,036

 
—

Mark-to-market derivative liabilities
(current liabilities)
 
(190
)
 
(3,243
)
 
(46
)
 
211

 
2,919

 
(159
)
 
(31
)
Mark-to-market derivative liabilities
(noncurrent liabilities)
 
(421
)
 
(1,442
)
 
(14
)
 
109

 
1,213

 
(134
)
 
(287
)
Total mark-to-market derivative liabilities
 
(611
)
 
(4,685
)
 
(60
)
 
320

 
4,132

 
(293
)
 
(318
)
Total mark-to-market derivative net assets (liabilities)
 
$
425

 
$
137

 
$
30

 
$
576

 
$
—

 
$
743

 
$
(318
)
December 31, 2019
 
Exelon
 
Generation
 
ComEd
Description
 
Total
Derivatives
 
Economic
Hedges
 
Proprietary
Trading
 
Collateral

(a)(b)
 
Netting (a)
 
Subtotal
 
Economic
Hedges
Mark-to-market derivative assets
(current assets)
 
$
675

 
$
3,506

 
$
72

 
$
287

 
$
(3,190
)
 
$
675

 
$
—

Mark-to-market derivative assets
(noncurrent assets)
 
508

 
1,238

 
25

 
122

 
(877
)
 
508

 
—

Total mark-to-market derivative assets
 
1,183

 
4,744

 
97

 
409

 
(4,067
)
 
1,183

 
—

Mark-to-market derivative liabilities
(current liabilities)
 
(236
)
 
(3,713
)
 
(38
)
 
357

 
3,190

 
(204
)
 
(32
)
Mark-to-market derivative liabilities
(noncurrent liabilities)
 
(380
)
 
(1,140
)
 
(11
)
 
163

 
877

 
(111
)
 
(269
)
Total mark-to-market derivative liabilities
 
(616
)
 
(4,853
)
 
(49
)
 
520

 
4,067

 
(315
)
 
(301
)
Total mark-to-market derivative net assets (liabilities)
 
$
567

 
$
(109
)
 
$
48

 
$
929

 
$
—

 
$
868

 
$
(301
)
_________
(a)
Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are not material and not reflected in the table above.
(b)
Of the collateral posted/(received), $383 million and $511 million represents variation margin on the exchanges at June 30, 2020 and December 31, 2019 respectively.

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

Note 11 — Derivative Financial Instruments

Economic Hedges (Commodity Price Risk)
Generation. For the three and six months ended June 30, 2020 and 2019, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2020
 
2019
 
2020
 
2019
Income Statement Location
 
Gain (Loss)
 
Gain (Loss)
Operating revenues
 
$
24

 
$
40

 
$
199

 
$
(10
)
Purchased power and fuel
 
63

 
(114
)
 
15

 
(84
)
Total Exelon and Generation
 
$
87

 
$
(74
)
 
$
214

 
$
(94
)

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, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 98%-101% and 76%-79% for 2020 and 2021, respectively.
Proprietary Trading (Commodity Price Risk)
Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the three and six months ended June 30, 2020 and 2019, net pre-tax commodity mark-to-market gains (losses) for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.
Interest Rate and Foreign Exchange Risk (Exelon and Generation)
Exelon and Generation utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $1,219 million and $1,269 million at June 30, 2020 and December 31, 2019, respectively, for Exelon and $519 million and $569 million at June 30, 2020 and December 31, 2019, respectively, for Generation.
Generation utilizes foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, which are treated as economic hedges. The notional amounts were $160 million and $231 million at June 30, 2020 and December 31, 2019, respectively.
The mark-to-market derivative assets and liabilities as of June 30, 2020 and December 31, 2019 and the mark-to-market gains and losses for the three and six months ended June 30, 2020 and 2019 were not material for Exelon and Generation.
Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date.
Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a

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

Note 11 — Derivative Financial Instruments

counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2020. 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. 
Rating as of June 30, 2020
 
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
 
$
772

 
$
25

 
$
747

 
1

 
$
117

Non-investment grade
 
35

 
26

 
9

 
 
 
 
No external ratings
 
 
 
 
 
 
 
 
 
 
Internally rated — investment grade
 
213

 
1

 
212

 
 
 
 
Internally rated — non-investment grade
 
130

 
17

 
113

 
 
 
 
Total
 
$
1,150

 
$
69

 
$
1,081

 
1

 
$
117

 
Net Credit Exposure by Type of Counterparty
 
As of
June 30, 2020
Financial institutions
 
$
29

Investor-owned utilities, marketers, power producers
 
834

Energy cooperatives and municipalities
 
173

Other
 
45

Total
 
$
1,081

_________ 
(a)
As of June 30, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $38 million of letters of credit. The credit collateral does not include non-liquid collateral.
Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of June 30, 2020, the Utility Registrants’ counterparty credit risk with suppliers was not material.
Credit-Risk-Related Contingent Features (All Registrants)
Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support

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Note 11 — Derivative Financial Instruments

requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:
Credit-Risk Related Contingent Features
 
June 30, 2020
 
December 31, 2019
Gross fair value of derivative contracts containing this feature(a)
 
$
(969
)
 
$
(956
)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)
 
697

 
649

Net fair value of derivative contracts containing this feature(c)
 
$
(272
)
 
$
(307
)
_________
(a)
Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.
(b)
Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
(c)
Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
As of June 30, 2020 and December 31, 2019, Exelon and Generation posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
 
 
June 30, 2020
 
December 31, 2019
Cash collateral posted
 
$
645

 
$
982

Letters of credit posted
 
224

 
264

Cash collateral held
 
110

 
103

Letters of credit held
 
76

 
112

Additional collateral required in the event of a credit downgrade below investment grade
 
1,319

 
1,509


Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.
Utility Registrants
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral.
PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE, and DPL’s credit rating. As of June 30, 2020, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE or DPL lost their investment grade

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

Note 11 — Derivative Financial Instruments

credit ratings as of June 30, 2020, they could have been required to post incremental collateral to its counterparties of $24 million, $26 million and $10 million, respectively.
12. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants' commercial paper programs as of June 30, 2020 and December 31, 2019. PECO had no commercial paper borrowings as of both June 30, 2020 and December 31, 2019.
 
Outstanding Commercial
Paper as of
 
Average Interest Rate on
Commercial Paper Borrowings as of
Commercial Paper Issuer
June 30, 2020
 
December 31, 2019
 
June 30, 2020
 
December 31, 2019
Exelon(a)
$
19

 
$
870

 
0.15
%
 
2.25
%
Generation
—

 
320

 
—
%
 
1.84
%
ComEd
—

 
130

 
—
%
 
2.38
%
BGE
—

 
76

 
—
%
 
2.46
%
PHI(b)
19

 
208

 
0.15
%
 
N/A

PEPCO
14

 
82

 
0.15
%
 
2.56
%
DPL
—

 
56

 
—
%
 
2.02
%
ACE
5

 
70

 
0.15
%
 
2.43
%

__________
(a)
Includes outstanding commercial paper at Exelon Corporate of $136 million with average interest rates on commercial paper borrowings of 1.92% at December 31, 2019. Exelon Corporate had no outstanding commercial paper borrowings as of June 30, 2020.
(b)
Includes the consolidated amounts of Pepco, DPL, and ACE.
On March 19, 2020, Generation borrowed $1.5 billion on its revolving credit facility due to disruptions in the commercial paper markets as a result of COVID-19. The funds were used to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020. As of June 30, 2020, the available capacity on Generation’s revolving credit facility was $5 billion. See Note 16— Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on the Registrants’ credit facilities.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed on March 19, 2020 and will expire on March 18, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-term borrowings.
On March 19, 2020, Generation entered into a term loan agreement for $200 million. The loan agreement has an expiration of March 18, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.50% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.

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

Note 12 — Debt and Credit Agreements

On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement has an expiration of March 30, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.75% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.
Revolving Credit Agreements
On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility at a variable interest rate of LIBOR plus 1.75%. This facility will be used by Exelon as an additional source of short-term liquidity as needed.
Bilateral Credit Agreements
On May 15, 2020, Generation entered into a credit agreement establishing a $100 million bilateral credit facility. This facility will solely be used by Generation to issue letters of credit, and the maturity date is automatically renewed based on the contingency standards set within the agreement.
During the second quarter of 2020, CENG drew on its bilateral credit facility. As of June 30, 2020, there was $100 million outstanding at this facility. The bilateral credit facility with CENG is incorporated within Generation, and supports the issuance of letters of credit and funding for working capital.

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

Note 12 — Debt and Credit Agreements

Long-Term Debt
Issuance of Long-Term Debt
During the six months ended June 30, 2020, the following long-term debt was issued:
Company(a)
 
Type
 
Interest Rate
 
Maturity
 
Amount
 
Use of Proceeds
Exelon
 
Notes
 
4.05
%
 
April 15, 2030
 
$
1,250

 
Repay existing indebtedness and for general corporate purposes.
Exelon
 
Notes
 
4.70
%
 
April 15, 2050
 
750

 
Repay existing indebtedness and for general corporate purposes.
Generation
 
Senior Notes
 
3.25
%
 
June 1, 2025
 
900

 
Repay existing indebtedness and for general corporate purposes.
Generation
 
Energy Efficiency Project Financing(b) 
 
3.95
%
 
August 31, 2020
 
2

 
Funding to install energy conservation measures for the Fort Meade project.
Generation
 
Energy Efficiency Project Financing(b)
 
2.53
%
 
April 30, 2021
 
1

 
Funding to install energy conservation measures for the Fort AP Hill project.
ComEd
 
First Mortgage Bonds, Series 128
 
2.20
%
 
March 1, 2030
 
350

 
Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes.
ComEd
 
First Mortgage Bonds, Series 129
 
3.00
%
 
March 1, 2050
 
650

 
Repay a portion of outstanding commercial paper obligations and to fund general corporate purposes.
PECO
 
First and Refunding Mortgage Bonds
 
2.80
%
 
June 15, 2050
 
350

 
Funding for general corporate purposes.
BGE
 
Senior Notes
 
2.90
%
 
June 15, 2050
 
400

 
Repay commercial paper obligations and for general corporate purposes.
Pepco(c)
 
First Mortgage Bonds
 
2.53
%
 
February 25, 2030
 
150

 
Repay existing indebtedness and for general corporate purposes.
DPL
 
First Mortgage Bonds
 
2.53
%
 
June 9, 2030
 
100

 
Repay existing indebtedness and for general corporate purposes.
ACE
 
Tax-Exempt First Mortgage Bonds
 
2.25
%
 
June 1, 2029
 
23

 
Refinance existing indebtedness.
ACE
 
First Mortgage Bonds
 
3.24
%
 
June 9, 2050
 
100

 
Repay existing indebtedness and for general corporate purposes.

__________
(a)
On July 1, 2020, DPL issued $78 million of tax-exempt bonds maturing on January 1, 2031. The bonds have a 1.05% interest rate through July 2025.
(b)
For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
(c)
On February 25, 2020, Pepco entered into a purchase agreement of First Mortgage Bonds for $150 million at 3.28% due on September 23, 2050. The closing date of the issuance is expected to occur in September 2020.
Debt Covenants
As of June 30, 2020, the Registrants are in compliance with debt covenants.
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.

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

Note 12 — Debt and Credit Agreements

As of June 30, 2020, approximately $475 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the project. As of June 30, 2020, Generation had $37 million in letters of credit outstanding related to the project. In 2017, Generation’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.
Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code, which created an event of default for Antelope Valley’s nonrecourse debt that provided 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 event of default and in the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019. Further, distributions from Antelope Valley to EGR IV were suspended.
The United States Bankruptcy Court entered an order on June 20, 2020 confirming PG&E’s plan of reorganization. On July 1, 2020 the plan became effective, and PG&E emerged from bankruptcy. On July 21, 2020, Antelope Valley received a waiver from the DOE for the event of default and, as such, the debt has been classified as noncurrent as of June 30, 2020 and distributions from Antelope Valley to EGR IV are now permitted.
See Note 8 — Asset Impairments for additional information.
ExGen Renewables IV.  In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this financing. The loan is scheduled to mature on November 28, 2024. As of June 30, 2020, approximately $775 million was outstanding.
See Note 16— Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on nonrecourse debt.
13. Fair Value of Financial Assets and Liabilities (All Registrants)
Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•
Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
•
Level 2 - inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
•
Level 3 - unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

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

Note 13 — Fair Value of Financial Assets and Liabilities

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, 2020 and December 31, 2019. The Registrants have no financial liabilities classified as Level 1.
The carrying amounts of the Registrants’ short-term liabilities as presented on their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.
 
 
June 30, 2020
 
December 31, 2019
 
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
 
 
 
Level 2
 
Level 3
 
Total
 
 
Level 2
 
Level 3
 
Total
Long-Term Debt, including amounts due within one year(a)

Exelon
 
$
38,626

 
$
41,531

 
$
3,080

 
$
44,611

 
$
36,039

 
$
37,453

 
$
2,580

 
$
40,033

Generation
 
7,433

 
6,761

 
1,418

 
8,179

 
7,974

 
7,304

 
1,366

 
8,670

ComEd
 
9,480

 
11,433

 
—

 
11,433

 
8,491

 
9,848

 
—

 
9,848

PECO
 
3,752

 
4,453

 
50

 
4,503

 
3,405

 
3,868

 
50

 
3,918

BGE
 
3,663

 
4,203

 
—

 
4,203

 
3,270

 
3,649

 
—

 
3,649

PHI
 
6,890

 
6,016

 
1,612

 
7,628

 
6,563

 
5,902

 
1,164

 
7,066

Pepco
 
3,013

 
3,270

 
576

 
3,846

 
2,864

 
3,198

 
388

 
3,586

DPL
 
1,675

 
1,444

 
443

 
1,887

 
1,567

 
1,408

 
311

 
1,719

ACE
 
1,420

 
1,040

 
593

 
1,633

 
1,327

 
1,026

 
464

 
1,490

Long-Term Debt to Financing Trusts(a)

Exelon
 
$
390

 
$
—

 
$
409

 
$
409

 
$
390

 
$
—

 
$
428

 
$
428

ComEd
 
205

 
—

 
216

 
216

 
205

 
—

 
227

 
227

PECO
 
184

 
—

 
192

 
192

 
184

 
—

 
201

 
201

SNF Obligation
Exelon
 
$
1,206

 
$
999

 
$
—

 
$
999

 
$
1,199

 
$
1,055

 
$
—

 
$
1,055

Generation
 
1,206

 
999

 
—

 
999

 
1,199

 
1,055

 
—

 
1,055

____
(a)
Includes unamortized debt issuance costs which are not fair valued.

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

Note 13 — Fair Value of Financial Assets and Liabilities

Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2020 and December 31, 2019:
Exelon and Generation
 
Exelon
 
Generation
As of June 30, 2020
Level 1
 
Level 2
 
Level 3
 
Not subject to leveling
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Not subject to leveling
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents(a)
$
1,864

 
$
—

 
$
—

 
$
—

 
$
1,864

 
$
162

 
$
—

 
$
—

 
$
—

 
$
162

NDT fund investments
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 

Cash equivalents(b)
345

 
78

 
—

 
—

 
423

 
345

 
78

 
—

 
—

 
423

Equities
3,080

 
1,599

 
—


1,280

 
5,959

 
3,080

 
1,599

 
—


1,280

 
5,959

Fixed income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Corporate debt
—

 
1,501

 
270

 
—

 
1,771

 
—

 
1,501

 
270

 
—

 
1,771

U.S. Treasury and agencies
1,864

 
116

 
—

 
—

 
1,980

 
1,864

 
116

 
—

 
—

 
1,980

Foreign governments
—

 
42

 
—

 
—

 
42

 
—

 
42

 
—

 
—

 
42

State and municipal debt
—

 
94

 
—

 
—

 
94

 
—

 
94

 
—

 
—

 
94

Other
—

 
29

 
—

 
965

 
994

 
—

 
29

 
—

 
965

 
994

Fixed income subtotal
1,864


1,782


270

 
965


4,881


1,864


1,782


270

 
965


4,881

Private credit
—

 
—

 
229

 
510

 
739

 
—

 
—

 
229

 
510

 
739

Private equity
—

 
—

 
—

 
423

 
423

 
—

 
—

 
—

 
423

 
423

Real estate
—

 
—

 
—

 
647

 
647

 
—

 
—

 
—

 
647

 
647

NDT fund investments subtotal(c)(d)
5,289


3,459


499

 
3,825


13,072


5,289


3,459


499

 
3,825


13,072

Rabbi trust investments
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 

Cash equivalents
50

 
—

 
—

 
—

 
50

 
4

 
—

 
—

 
—

 
4

Mutual funds
79

 
—

 
—

 
—

 
79

 
25

 
—

 
—

 
—

 
25

Fixed income
—

 
10

 
—

 
—

 
10

 
—

 
—

 
—

 
—

 
—

Life insurance contracts
—

 
77

 
43

 
—

 
120

 
—

 
24

 
—

 
—

 
24

Rabbi trust investments subtotal
129


87


43

 
—


259


29


24


—

 
—


53

Commodity derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Economic hedges
770

 
2,382

 
1,670

 
—

 
4,822

 
770

 
2,382

 
1,670

 
—

 
4,822

Proprietary trading
—

 
47

 
43

 
—

 
90

 
—

 
47

 
43

 
—

 
90

Effect of netting and allocation of collateral(e)(f)
(849
)
 
(2,124
)
 
(903
)
 
—

 
(3,876
)
 
(849
)
 
(2,124
)
 
(903
)
 
—

 
(3,876
)
Commodity derivative assets subtotal
(79
)

305


810

 
—


1,036


(79
)

305


810

 
—


1,036

DPP consideration
—

 
635

 
—

 
—

 
635

 
—

 
635

 
—

 
—

 
635

Total assets
7,203


4,486


1,352


3,825


16,866


5,401


4,423


1,309


3,825


14,958


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

Note 13 — Fair Value of Financial Assets and Liabilities

 
Exelon
 
Generation
As of June 30, 2020
Level 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
(933
)
 
(2,541
)
 
(1,529
)
 
—

 
(5,003
)
 
(933
)
 
(2,541
)
 
(1,211
)
 
—

 
(4,685
)
Proprietary trading
—

 
(44
)
 
(16
)
 
—

 
(60
)
 
—

 
(44
)
 
(16
)
 
—

 
(60
)
Effect of netting and allocation of collateral(e)(f)
933

 
2,443

 
1,076

 
—

 
4,452

 
933

 
2,443

 
1,076

 
—

 
4,452

Commodity derivative liabilities subtotal
—

 
(142
)
 
(469
)
 
—

 
(611
)
 
—

 
(142
)
 
(151
)
 
—

 
(293
)
Deferred compensation obligation
—

 
(127
)
 
—

 
—

 
(127
)
 
—

 
(35
)
 
—

 
—

 
(35
)
Total liabilities
—


(269
)

(469
)
 
—


(738
)

—


(177
)

(151
)
 
—


(328
)
Total net assets
$
7,203


$
4,217


$
883

 
$
3,825


$
16,128


$
5,401


$
4,246


$
1,158

 
$
3,825


$
14,630


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

Note 13 — Fair Value of Financial Assets and Liabilities

 
Exelon
 
Generation
As of December 31, 2019
Level 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)
$
639

 
$
—

 
$
—

 
$
—

 
$
639

 
$
214

 
$
—

 
$
—

 
$
—

 
$
214

NDT fund investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


Cash equivalents(b)
365

 
87

 
—

 
—

 
452

 
365

 
87

 
—

 
—

 
452

Equities
3,353


1,753


—


1,388


6,494


3,353


1,753


—


1,388


6,494

Fixed income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Corporate debt
—

 
1,469

 
257

 
—

 
1,726

 
—

 
1,469

 
257

 
—

 
1,726

U.S. Treasury and agencies
1,808

 
131

 
—

 
—

 
1,939

 
1,808

 
131

 
—

 
—

 
1,939

Foreign governments
—

 
42

 
—

 
—

 
42

 
—

 
42

 
—

 
—

 
42

State and municipal debt
—

 
90

 
—

 
—

 
90

 
—

 
90

 
—

 
—

 
90

Other
—

 
33

 
—

 
953

 
986

 
—

 
33

 
—

 
953

 
986

Fixed income subtotal
1,808


1,765


257

 
953


4,783


1,808


1,765


257

 
953


4,783

Private credit
—

 
—

 
254

 
508

 
762

 
—

 
—

 
254

 
508

 
762

Private equity
—

 
—

 
—

 
402

 
402

 
—

 
—

 
—

 
402

 
402

Real estate
—

 
—

 
—

 
607

 
607

 
—

 
—

 
—

 
607

 
607

NDT fund investments subtotal(c)(d)
5,526


3,605


511

 
3,858


13,500


5,526


3,605


511

 
3,858

 
13,500

Rabbi trust investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
50

 
—

 
—

 
—

 
50

 
4

 
—

 
—

 
—

 
4

Mutual funds
81

 
—

 
—

 
—

 
81

 
25

 
—

 
—

 
—

 
25

Fixed income
—

 
12

 
—

 
—

 
12

 
—

 
—

 
—

 
—

 
—

Life insurance contracts
—

 
78

 
41

 
—

 
119

 
—

 
25

 
—

 
—

 
25

Rabbi trust investments subtotal
131


90


41

 
—


262


29


25


—

 
—


54

Commodity derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Economic hedges
768

 
2,491

 
1,485

 
—

 
4,744

 
768

 
2,491

 
1,485

 
—

 
4,744

Proprietary trading
—

 
37

 
60

 
—

 
97

 
—

 
37

 
60

 
—

 
97

Effect of netting and allocation of collateral(e)(f)
(908
)
 
(2,162
)
 
(588
)
 
—

 
(3,658
)
 
(908
)
 
(2,162
)
 
(588
)
 
—

 
(3,658
)
Commodity derivative assets subtotal
(140
)

366


957

 
—


1,183


(140
)

366


957

 
—


1,183

Total assets
6,156


4,061


1,509


3,858


15,584


5,629


3,996


1,468


3,858


14,951


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

Note 13 — Fair Value of Financial Assets and Liabilities

 
Exelon
 
Generation
As of December 31, 2019
Level 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
(1,071
)
 
(2,855
)
 
(1,228
)
 
—

 
(5,154
)
 
(1,071
)
 
(2,855
)
 
(927
)
 
—

 
(4,853
)
Proprietary trading
—

 
(34
)
 
(15
)
 
—

 
(49
)
 
—

 
(34
)
 
(15
)
 
—

 
(49
)
Effect of netting and allocation of collateral(e)(f)
1,071

 
2,714

 
802

 
—

 
4,587

 
1,071

 
2,714

 
802

 
—

 
4,587

Commodity derivative liabilities subtotal
—


(175
)

(441
)
 
—


(616
)

—


(175
)

(140
)
 
—


(315
)
Deferred compensation obligation
—

 
(147
)
 
—

 
—

 
(147
)
 
—

 
(41
)
 
—

 
—

 
(41
)
Total liabilities
—


(322
)

(441
)
 
—


(763
)

—


(216
)

(140
)
 
—


(356
)
Total net assets
$
6,156


$
3,739


$
1,068

 
$
3,858


$
14,821


$
5,629


$
3,780


$
1,328

 
$
3,858


$
14,595

_________
(a)
Exelon excludes cash of $684 million and $373 million at June 30, 2020 and December 31, 2019, respectively, and restricted cash of $132 million and $110 million at June 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $178 million and $177 million at June 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $401 million and $177 million at June 30, 2020 and December 31, 2019, respectively, and restricted cash of $73 million and $58 million at June 30, 2020 and December 31, 2019, respectively. 
(b)
Includes $101 million and $90 million of cash received from outstanding repurchase agreements at June 30, 2020 and December 31, 2019, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.
(c)
Includes derivative assets of less than $1 million and $2 million, which have total notional amounts of $769 million and $724 million at June 30, 2020 and December 31, 2019, 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 $155 million and $147 million at June 30, 2020 and December 31, 2019, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.
(e)
Collateral posted/(received) from counterparties totaled $84 million, $319 million and $173 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, 2020. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $163 million, $551 million and $214 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2019.
(f)
Of the collateral posted/(received), $383 million and $511 million represents variation margin on the exchanges as of June 30, 2020 and December 31, 2019, respectively.
As of June 30, 2020, Exelon and Generation have outstanding commitments to invest in fixed income, private credit, private equity and real estate investments of approximately $58 million, $147 million, $316 million, and $410 million, respectively. These commitments will be funded by Generation’s existing NDT funds.
Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $76 million and $66 million as of June 30, 2020, respectively. Changes in fair value, cumulative adjustments and impairments were not material for the three and six months ended June 30, 2020.

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

Note 13 — Fair Value of Financial Assets and Liabilities

ComEd, PECO and BGE
 
ComEd
 
PECO
 
BGE
As of June 30, 2020
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents(a)
$
578

 
$
—

 
$
—

 
$
578

 
$
353

 
$
—

 
$
—

 
$
353

 
$
188

 
$
—

 
$
—

 
$
188

Rabbi trust investments
 
 
 
 
 
 

 
 
 
 
 
 
 

 
 
 
 
 
 
 

Mutual funds
—

 
—

 
—

 
—

 
8

 
—

 
—

 
8

 
10

 
—

 
—

 
10

Life insurance contracts
—

 
—

 
—

 
—

 
—

 
11

 
—

 
11

 
—

 
—

 
1

 
1

Rabbi trust investments subtotal
—


—


—


—


8


11


—


19


10


—


1


11

Total assets
578


—


—


578


361


11


—


372


198


—


1


199

Liabilities
 
 
 
 
 
 

 
 
 
 
 
 
 

 
 
 
 
 
 
 

Deferred compensation obligation
—

 
(6
)
 
—

 
(6
)
 
—

 
(8
)
 
—

 
(8
)
 
—

 
(5
)
 
—

 
(5
)
Mark-to-market derivative liabilities(b)
—

 
—

 
(318
)
 
(318
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total liabilities
—

 
(6
)
 
(318
)
 
(324
)
 
—

 
(8
)
 
—

 
(8
)
 
—

 
(5
)
 
—

 
(5
)
Total net assets (liabilities)
$
578

 
$
(6
)
 
$
(318
)
 
$
254

 
$
361

 
$
3

 
$
—

 
$
364

 
$
198

 
$
(5
)
 
$
1

 
$
194

 
ComEd
 
PECO
 
BGE
As of December 31, 2019
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents(a)
$
280

 
$
—

 
$
—

 
$
280

 
$
15

 
$
—

 
$
—

 
$
15

 
$
—

 
$
—

 
$
—

 
$
—

Rabbi trust investments
 
 
 
 
 
 

 
 
 
 
 
 
 

 
 
 
 
 
 
 

Mutual funds
—

 
—

 
—

 
—

 
8

 
—

 
—

 
8

 
8

 
—

 
—

 
8

Life insurance contracts
—

 
—

 
—

 
—

 
—

 
11

 
—

 
11

 
—

 
—

 
—

 
—

Rabbi trust investments subtotal
—


—


—


—


8


11


—


19


8


—


—


8

Total assets
280


—


—


280


23


11


—


34


8


—


—


8

Liabilities
 
 
 
 
 
 

 
 
 
 
 
 
 

 
 
 
 
 
 
 

Deferred compensation obligation
—

 
(8
)
 
—

 
(8
)
 
—

 
(9
)
 
—

 
(9
)
 
—

 
(5
)
 
—

 
(5
)
Mark-to-market derivative liabilities(b)
—

 
—

 
(301
)
 
(301
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total liabilities
—

 
(8
)
 
(301
)
 
(309
)
 
—

 
(9
)
 
—

 
(9
)
 
—

 
(5
)
 
—

 
(5
)
Total net assets (liabilities)
$
280

 
$
(8
)
 
$
(301
)
 
$
(29
)
 
$
23

 
$
2

 
$
—

 
$
25

 
$
8

 
$
(5
)
 
$
—

 
$
3

_________
(a)
ComEd excludes cash of $109 million and $90 million at June 30, 2020 and December 31, 2019, respectively, and restricted cash of $37 million and $33 million at June 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $166 million and $163 million at June 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  PECO excludes cash of $34 million and $12 million at June 30, 2020 and December 31, 2019, respectively.  BGE excludes cash of $7 million and $24 million at June 30, 2020 and December 31, 2019, respectively, and restricted cash of $1 million at both June 30, 2020 and December 31, 2019.
(b)
The Level 3 balance consists of the current and noncurrent liability of $31 million and $287 million, respectively, at June 30, 2020, and $32 million and $269 million, respectively, at December 31, 2019, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.




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

Note 13 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL and ACE
 
As of June 30, 2020
 
As of December 31, 2019
PHI
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents(a)
$
50

 
$
—

 
$
—

 
$
50

 
$
124

 
$
—

 
$
—

 
$
124

Rabbi trust investments
 
 
 
 
 
 

 
 
 
 
 
 
 

Cash equivalents
44

 
—

 
—

 
44

 
44

 
—

 
—

 
44

Mutual funds
13

 
—

 
—

 
13

 
14

 
—

 
—

 
14

Fixed income
—

 
10

 
—

 
10

 
—

 
12

 
—

 
12

Life insurance contracts
—

 
24

 
43

 
67

 
—

 
24

 
41

 
65

Rabbi trust investments subtotal
57


34


43


134


58


36


41


135

Total assets
107


34


43


184

 
182


36


41


259

Liabilities
 
 
 
 
 
 

 
 
 
 
 
 
 

Deferred compensation obligation
—

 
(16
)
 
—

 
(16
)
 
—

 
(19
)
 
—

 
(19
)
Total liabilities
—


(16
)

—


(16
)

—


(19
)

—


(19
)
Total net assets
$
107


$
18


$
43


$
168

 
$
182


$
17


$
41


$
240

 
Pepco
 
DPL
 
ACE
As of June 30, 2020
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets

 

 

 

 

 

 

 

 

 

 

 

Cash equivalents(a)
$
34

 
$
—

 
$
—

 
$
34

 
$
—

 
$
—

 
$
—

 
$
—

 
$
14

 
$
—

 
$
—

 
$
14

Rabbi trust investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
43

 
—

 
—

 
43

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Fixed income
—

 
2

 
—

 
2

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Life insurance contracts
—

 
24

 
42

 
66

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Rabbi trust investments subtotal
43


26


42


111


—


—


—


—


—


—


—


—

Total assets
77


26


42


145


—


—


—


—


14


—


—


14

Liabilities

 

 

 


 

 

 

 

 

 

 

 

Deferred compensation obligation
—

 
(2
)
 
—

 
(2
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total liabilities
—


(2
)

—


(2
)

—


—


—


—


—


—


—


—

Total net assets
$
77

 
$
24

 
$
42

 
$
143

 
$
—

 
$
—

 
$
—

 
$
—

 
$
14

 
$
—

 
$
—

 
$
14


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

Note 13 — Fair Value of Financial Assets and Liabilities


Pepco
 
DPL
 
ACE
As of December 31, 2019
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets

 

 

 

 

 

 

 

 

 

 

 

Cash equivalents(a)
$
34

 
$
—

 
$
—

 
$
34

 
$
—

 
$
—

 
$
—

 
$
—

 
$
16

 
$
—

 
$
—

 
$
16

Rabbi trust investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
43

 
—

 
—

 
43

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Fixed income
—

 
2

 
—

 
2

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Life insurance contracts
—

 
24

 
41

 
65

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Rabbi trust investments subtotal
43


26


41


110


—


—


—


—


—


—


—


—

Total assets
77


26


41


144


—


—


—


—


16


—


—


16

Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred compensation obligation
—

 
(2
)
 
—

 
(2
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total liabilities
—

 
(2
)
 
—

 
(2
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total net assets (liabilities)
$
77

 
$
24

 
$
41


$
142

 
$
—

 
$
—

 
$
—

 
$
—

 
$
16

 
$
—

 
$
—

 
$
16

_________
(a)
PHI excludes cash of $36 million and $57 million at June 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $11 million and $14 million at June 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  Pepco excludes cash of $18 million and $29 million at June 30, 2020 and December 31, 2019, respectively. DPL excludes cash of $6 million and $13 million at June 30, 2020 and December 31, 2019, respectively. ACE excludes cash of $8 million and $12 million at June 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $11 million and $14 million at June 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.

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

Note 13 — Fair Value of Financial Assets and Liabilities

Reconciliation of Level 3 Assets and Liabilities
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, 2020 and 2019:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exelon
 
Generation
 
ComEd
 
PHI and Pepco
 
 
Three Months Ended June 30, 2020
Total
 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 
Total Generation
 
Mark-to-Market
Derivatives
 
Life Insurance Contracts
 
Eliminated in Consolidation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance as of March 31, 2020
$
1,088

 
$
498

 
$
862

 
$
1,360

 
$
(314
)
 
$
42

 
$
—

Total realized / unrealized gains (losses)

 
 
 
 
 

 
 
 
 
 
 
Included in net income
(166
)
 
(1
)
 
(166
)
(a) 
(167
)
 
—

 
1

 
—

Included in regulatory assets/liabilities
(4
)
 
—

 
—

 
—

 
(4
)
(b) 
—

 
—

Change in collateral
(42
)
 
—

 
(42
)
 
(42
)
 
—

 
—

 
—

Purchases, sales, issuances and settlements


 
 
 
 
 

 
 
 
 
 
 
Purchases
30

 
3

 
27

 
30

 
—

 
—

 
—

Sales
(2
)
 
—

 
(2
)
 
(2
)
 
—

 
—

 
—

Settlements
(1
)
 
(1
)
 
—

 
(1
)
 
—

 
—

 
—

Transfers into Level 3
(9
)
 
—

 
(9
)
(c) 
(9
)
 
—

 
—

 
—

Transfers out of Level 3
(11
)
 
—

 
(11
)
(c) 
(11
)
 
—

 
—

 
—

Balance at June 30, 2020
$
883

 
$
499

 
$
659

 
$
1,158

 
$
(318
)
 
$
43

 
$
—

The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2020
$
(72
)
 
$
(1
)
 
$
(72
)
 
$
(73
)
 
$
—

 
$
1

 
$
—

 
Exelon
 
Generation
 
ComEd
 
PHI and Pepco
 
 
Six months ended June 30, 2020
Total
 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 
Total Generation
 
Mark-to-Market
Derivatives
 
Life Insurance Contracts
 
Eliminated in Consolidation
Balance as of December 31, 2019
$
1,068

 
$
511

 
$
817

 
$
1,328

 
$
(301
)
 
$
41

 
$
—

Total realized / unrealized gains (losses)


 
 
 
 
 


 
 
 
 
 
 
Included in net income
(156
)
 
(2
)
 
(156
)
(a) 
(158
)
 
—

 
2

 
—

Included in noncurrent payables to affiliates
—

 
(1
)
 
—

 
(1
)
 
—

 
—

 
1

Included in regulatory assets
(18
)
 
—

 
—

 
—

 
(17
)
(b) 
—

 
(1
)
Change in collateral
(41
)
 
—

 
(41
)
 
(41
)
 
—

 
—

 
—

Purchases, sales, issuances and settlements


 
 
 
 
 


 
 
 
 
 
 
Purchases
71

 
6

 
65

 
71

 
—

 
—

 
—

Sales
(24
)
 
—

 
(24
)
 
(24
)
 
—

 
—

 
—

Settlements
(15
)
 
(15
)
 
—

 
(15
)
 
—

 
—

 
—

Transfers into Level 3
(6
)
 
—

 
(6
)
(c) 
(6
)
 
—

 
—

 
—

Transfers out of Level 3
4

 
—

 
4

(c) 
4

 
—

 
—

 
—

Balance as of June 30, 2020
$
883

 
$
499

 
$
659

 
$
1,158

 
$
(318
)
 
$
43

 
$
—

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, 2020
$
115

 
$
(2
)
 
$
115

 
$
113

 
$
—

 
$
2

 
$
—




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

Note 13 — Fair Value of Financial Assets and Liabilities

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Exelon
 
Generation
 
ComEd
 
PHI and Pepco
 
 
Three Months Ended June 30, 2019
Total
 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 
Total Generation
 
Mark-to-Market
Derivatives
 
Life Insurance Contracts
 
Eliminated in Consolidation
Balance as of March 31, 2019
$
838

 
$
540

 
$
499

 
$
1,039

 
$
(240
)
 
$
39

 
$
—

Total realized / unrealized gains (losses)
 
 
 
 
 
 


 
 
 
 
 
 
Included in net income
275

 
2

 
272

(a) 
274

 
—

 
1

 
—

Included in noncurrent payables to affiliates
—

 
10

 
—

 
10

 
—

 
—

 
(10
)
Included in regulatory assets
(23
)
 
—

 
—

 
—

 
(33
)
(b) 
—

 
10

Change in collateral
106

 
—

 
106

 
106

 
—

 
—

 
—

Purchases, sales, issuances and settlements

 
 
 
 
 


 
 
 
 
 
 
Purchases
51

 
40

 
11

 
51

 
—

 
—

 
—

Sales
(1
)
 
—

 
(1
)
 
(1
)
 
—

 
—

 
—

Settlements
(53
)
 
(53
)
 
—

 
(53
)
 
—

 
—

 
—

Transfers into Level 3
3

 
—

 
3

(c) 
3

 
—

 
—

 
—

Transfers out of Level 3
(17
)
 
—

 
(17
)
(c) 
(17
)
 
—

 
—

 
—

Balance as of June 30, 2019
$
1,179

 
$
539


$
873


$
1,412


$
(273
)

$
40

 
$
—

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2019
$
339

 
$
1

 
$
337

 
$
338

 
$
—

 
$
1

 
$
—


 
Exelon
 
Generation
 
ComEd
 
PHI and Pepco
 
 
Six Months Ended June 30, 2019
Total
 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 
Total Generation
 
Mark-to-Market
Derivatives
 
Life Insurance Contracts
 
Eliminated in Consolidation
Balance as of December 31, 2018
$
907

 
$
543

 
$
575

 
$
1,118

 
$
(249
)
 
$
38

 
$
—

Total realized / unrealized gains (losses)

 
 
 
 
 


 
 
 
 
 
 
Included in net income
46

 
3

 
41

(a) 
44

 
—

 
2

 
—

Included in noncurrent payables to affiliates
—

 
21

 
—

 
21

 
—

 
—

 
(21
)
Included in regulatory assets
(3
)
 
—

 
—

 
—

 
(24
)
(b) 
—

 
21

Change in collateral
187

 
—

 
187

 
187

 
—

 
—

 
—

Purchases, sales, issuances and settlements

 
 
 
 
 


 
 
 
 
 
 
Purchases
110

 
42

 
68

 
110

 
—

 
—

 
—

Sales
(1
)
 
—

 
(1
)
 
(1
)
 
—

 
—

 
—

Settlements
(70
)
 
(70
)
 
—

 
(70
)
 
—

 
—

 
—

Transfers into Level 3
3

 
—

 
3

(c) 
3

 
—

 
—

 
—

Transfers out of Level 3
—

 
—

 
—

(c) 
—

 
—

 
—

 
—

Balance as of June 30, 2019
$
1,179

 
$
539

 
$
873

 
$
1,412


$
(273
)
 
$
40

 
$
—

The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2019
$
191

 
$
3

 
$
186

 
$
189

 
$
—

 
$
2

 
$
—



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

Note 13 — Fair Value of Financial Assets and Liabilities

__________
(a)
Includes a reduction for the reclassification of $94 million and $271 million of realized losses due to the settlement of derivative contracts for the three and six months ended June 30, 2020. Includes a reduction for the reclassification of $65 million and $145 million of realized losses due to the settlement of derivative contracts for the three and six months ended June 30, 2019.
(b)
Includes $12 million of decreases in fair value and an increase for realized losses due to settlements of $8 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2020. Includes $35 million of decreases in fair value and an increase for realized losses due to settlements of $18 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2020. Includes $41 million of decreases in fair value and an increase for realized losses due to settlements of $8 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2019. Includes $37 million of decreases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2019.
(c)
Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.
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, 2020 and 2019:
 
Exelon
 
Generation
 
PHI and Pepco
 
Operating
Revenues
 
Purchased
Power and
Fuel
 
Operating and Maintenance
 
Other, net
 
Operating
Revenues
 
Purchased
Power and
Fuel
 
Other, net
 
Operating and Maintenance
Total realized (losses) gains for the three months ended June 30, 2020
$
(137
)
 
$
(29
)
 
$
1

 
$
—

 
$
(137
)
 
$
(29
)
 
$
—

 
$
1

Total realized (losses) gains for the six months ended June 30, 2020
(65
)
 
(91
)
 
2

 
—

 
(65
)
 
(91
)
 
—

 
2

Total unrealized (losses) gains for the three months ended June 30, 2020
(39
)
 
(33
)
 
1

 
(1
)
 
(39
)
 
(33
)
 
(1
)
 
1

Total unrealized gains (losses) for the six months ended June 30, 2020
166

 
(51
)
 
2

 
(2
)
 
166

 
(51
)
 
(2
)
 
2

 
Exelon
 
Generation
 
PHI and Pepco
 
Operating
Revenues
 
Purchased
Power and
Fuel
 
Operating and Maintenance
 
Other, net
 
Operating
Revenues
 
Purchased
Power and
Fuel
 
Other, net
 
Operating and Maintenance
Total realized gains (losses) for the three months ended June 30, 2019
$
275

 
$
(3
)
 
$
1

 
$
2

 
$
275

 
$
(3
)
 
$
2

 
$
1

Total realized gains (losses) for the six months ended June 30, 2019
147

 
(106
)
 
2

 
3

 
147

 
(106
)
 
3

 
2

Total unrealized gains (losses) for the three months ended June 30, 2019
360

 
(23
)
 
1

 
1

 
360

 
(23
)
 
1

 
1

Total unrealized gains (losses) gains for the six months ended June 30, 2019
269

 
(83
)

2


3

 
269

 
(83
)
 
3

 
2



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

Note 13 — Fair Value of Financial Assets and Liabilities

Valuation Techniques Used to Determine Fair Value
Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of the Exelon 2019 Form 10-K.
Valuation Techniques Used to Determine Net asset Value (Exelon and Generation)
Certain NDT Fund Investments are not classified within the fair value hierarchy and are included under the heading “Not subject to leveling” in the table above. These investments are measured at fair value using NAV per share as a practical expedient and include commingled funds, mutual funds which are not publicly quoted, managed private credit funds, private equity and real estate funds.
For commingled funds and mutual funds, which are not publicly quoted, the fair value is primarily derived from the quoted prices in active markets on the underlying securities and can typically be redeemed monthly with 30 or less days of notice and without further restrictions. For managed private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon’s understanding of the investment funds. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.
Deferred Purchase Price Consideration (Exelon and Generation)
Exelon and Generation have DPP consideration for the sale of certain receivables of retail electricity at Generation. This amount is valued based on the sales price of the receivables net of allowance for credit losses based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. Since the DPP consideration is based on the sales price of the receivables, it is categorized as Level 2 in the fair value hierarchy. See Note 5 - Accounts Receivable for additional information on the sale of certain receivables.













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

Note 13 — Fair Value of Financial Assets and Liabilities

Mark-to-Market Derivatives (Exelon, Generation and ComEd)
The table below discloses the significant inputs to the forward curve used to value mark-to-market derivatives.
Type of trade
 
Fair Value at June 30, 2020
 
Fair Value at December 31, 2019
 
Valuation
Technique
 
Unobservable
Input
 
2020 Range & Arithmetic Average
 
2019 Range & Arithmetic Average
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)
 
$
459

 
$
558

 
Discounted
Cash Flow
 
Forward power
price
 
$7
-
$148
$28
 
$9
-
$180
$29
 
 


 
 
 

 
Forward gas
price
 
$1.45
-
$7.66
$2.58
 
$0.83
-
$10.72
$2.55
 
 


 
 
 
Option
Model
 
Volatility
percentage
 
9%
-
522%
92%
 
8%
-
236%
70%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
 
$
27

 
$
45

 
Discounted
Cash Flow
 
Forward power
price
 
$13
-
$148
$32
 
$25
-
$180
$33
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mark-to-market derivatives (Exelon and ComEd)
 
$
(318
)
 
$
(301
)
 
Discounted
Cash Flow
 
Forward heat
rate(c)
 
8x
-
9x
8.85x
 
9x
-
10x
9.68x
 
 
 
 
 
 
 
 
Marketability
reserve
 
4%
-
8%
5.24%
 
3%
-
7%
4.95%
 
 
 
 
 
 
 
 
Renewable
factor
 
93%
-
122%
100%
 
91%
-
123%
99%

_________
(a)
The valuation techniques, unobservable inputs, ranges and arithmetic averages are the same for the asset and liability positions.
(b)
The fair values do not include cash collateral posted on level three positions of $173 million and $214 million as of June 30, 2020 and December 31, 2019, 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.
14. Commitments and Contingencies (All Registrants)
The following is an update to the current status of commitments and contingencies set forth in Note 18 of the Exelon 2019 Form 10-K.
Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain

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

Note 14 — Commitments and Contingencies

commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL and ACE as of June 30, 2020:
Description
Exelon
 
PHI
 
Pepco
 
DPL
 
ACE
Total commitments
$
513

 
$
320

 
$
120

 
$
89

 
$
111

Remaining commitments(a)
91

 
72

 
60

 
7

 
5


_________
(a)
Remaining commitments extend through 2026 and include rate credits, energy efficiency programs and delivery system modernization.
In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia, and Delaware at an estimated cost of approximately $127 million, which will generate future earnings at Exelon and Generation. Investment costs, which are expected to be primarily capital in nature, are recognized as incurred and recorded in Exelon's and Generation's financial statements. As of June 30, 2020, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $123 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 2019. The third and final 40 MW wind REC tranche will be conducted in 2022.

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

Note 14 — Commitments and Contingencies

Commercial Commitments (All Registrants). The Registrants’ commercial commitments as of June 30, 2020, representing commitments potentially triggered by future events were as follows:
 
 
 
Expiration within
 
Total
 
2020
 
2021
 
2022
 
2023
 
2024
 
2025 and beyond
Exelon
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit
$
1,291

 
$
475

 
$
816

 
$
—

 
$
—

 
$
—

 
$
—

Surety bonds(a)
902

 
550

 
335

 
17

 
—

 
—

 
—

Financing trust guarantees
378

 
—

 
—

 
—

 
—

 
—

 
378

Guaranteed lease residual values(b)
28

 
1

 
2

 
4

 
3

 
7

 
11

Total commercial commitments
$
2,599

 
$
1,026

 
$
1,153

 
$
21

 
$
3


$
7

 
$
389

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit
$
1,276

 
$
467

 
$
809

 
$
—

 
$
—

 
$
—

 
$
—

Surety bonds(a)
754

 
479

 
258

 
17

 
—

 
—

 
—

Total commercial commitments
$
2,030

 
$
946

 
$
1,067

 
$
17

 
$
—

 
$
—

 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
ComEd
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit
$
7

 
$
4

 
$
3

 
$
—

 
$
—

 
$
—

 
$
—

Surety bonds(a)
15

 
8

 
7

 
—

 
—

 
—

 
—

Financing trust guarantees
200

 
—

 
—

 
—

 
—

 
—

 
200

Total commercial commitments
$
222

 
$
12

 
$
10

 
$
—

 
$
—

 
$
—

 
$
200

 
 
 
 
 
 
 
 
 
 
 
 
 
 
PECO
 
 
 
 
 
 
 
 
 
 
 
 
 
Surety bonds(a)
$
6

 
$
4

 
$
2

 
$
—

 
$
—

 
$
—

 
$
—

Financing trust guarantees
178

 
—

 
—

 
—

 
—

 
—

 
178

Total commercial commitments
$
184

 
$
4

 
$
2

 
$
—

 
$
—

 
$
—

 
$
178

 
 
 
 
 
 
 
 
 
 
 
 
 
 
BGE
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit
$
2

 
$
2

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Surety bonds(a)
3

 
2

 
1

 
—

 
—

 
—

 
—

Total commercial commitments
$
5

 
$
4

 
$
1

 
$
—

 
$
—

 
$
—

 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
PHI
 
 
 
 
 
 
 
 
 
 
 
 
 
Surety bonds(a)
$
22

 
$
6

 
$
16

 
$
—

 
$
—

 
$
—

 
$
—

Guaranteed lease residual values(b)
28

 
1

 
2

 
4

 
3

 
7

 
11

Total commercial commitments
$
50

 
$
7

 
$
18

 
$
4

 
$
3

 
$
7

 
$
11

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pepco
 
 
 
 
 
 
 
 
 
 
 
 
 
Surety bonds(a)
$
14

 
$
1

 
$
13

 
$
—

 
$
—

 
$
—

 
$
—

Guaranteed lease residual values(b)
9

 
—

 
1

 
1

 
1

 
2

 
4

Total commercial commitments
$
23

 
$
1

 
$
14

 
$
1

 
$
1

 
$
2

 
$
4

 
 
 
 
 
 
 
 
 
 
 
 
 
 
DPL
 
 
 
 
 
 
 
 
 
 
 
 
 
Surety bonds(a)
$
4

 
$
3

 
$
1

 
$
—

 
$
—

 
$
—

 
$
—

Guaranteed lease residual values(b)
12

 
—

 
1

 
2

 
1

 
4

 
4

Total commercial commitments
$
16

 
$
3

 
$
2

 
$
2

 
$
1

 
$
4

 
$
4

 
 
 
 
 
 
 
 
 
 
 
 
 
 
ACE
 
 
 
 
 
 
 
 
 
 
 
 
 
Surety bonds(a)
$
4

 
$
2

 
$
2

 
$
—

 
$
—

 
$
—

 
$
—

Guaranteed lease residual values(b)
7

 
1

 
—

 
1

 
1

 
1

 
3

Total commercial commitments
$
11

 
$
3

 
$
2

 
$
1

 
$
1

 
$
1

 
$
3

_________
(a)
Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

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Note 14 — Commitments and Contingencies

(b)
Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $74 million guaranteed by Exelon and PHI, of which $25 million, $31 million and $18 million is guaranteed by Pepco, DPL and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
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 on the Registrants' financial statements.
MGP Sites (Exelon and the Utility Registrants). 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 21 sites 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 2025.
•
PECO has 8 sites 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 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2021.
•
DPL has 1 site that is currently under study and the required cost at the site is not expected to be material.
The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.

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

Note 14 — Commitments and Contingencies

As of June 30, 2020 and December 31, 2019, 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, 2020
 
December 31, 2019
 
Total environmental
investigation and
remediation liabilities
 
Portion of total related to
MGP investigation and
remediation
 
Total environmental
investigation and
remediation liabilities
 
Portion of total related to
MGP investigation and
remediation
Exelon
$
463


$
309

 
$
478


$
320

Generation
103

 
—

 
105

 
—

ComEd
293

 
292

 
304

 
303

PECO
19

 
17

 
19

 
17

BGE
2

 
—

 
2

 
—

PHI
46


—

 
48


—

Pepco
44

 
—

 
46

 
—

DPL
1

 
—

 
1

 
—

ACE
1

 
—

 
1

 
—

Cotter Corporation (Exelon and Generation). The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.
In September 2018, the EPA issued its Record of Decision (ROD) Amendment for the selection of a final remedy. The ROD Amendment modified the remedy previously selected by EPA in its 2008 ROD. While the ROD required only that the radiological materials and other wastes at the site be capped, the ROD Amendment requires partial excavation of the radiological materials in addition to the previously selected capping remedy. The ROD Amendment also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed by early 2022. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Cotter (Generation’s indemnitee) provided a non-binding good faith offer to conduct, or finance, a portion of the remedy, subject to certain conditions. The total estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred collectively by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required 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 Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.
One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial statements.
In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative

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Note 14 — Commitments and Contingencies

Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation (RI)/Feasibility Study (FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $20 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future financial statements.
In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s (now Generation'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. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 28, 2021 so that settlement discussions can proceed. On August 3, 2020, the DOJ advised Cotter and the other PRPs that it is seeking approximately $90 million from all the PRPs and that the PRPs must submit a good faith joint proposed settlement offer by December 1, 2020. 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.
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, which was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River.
Since 2013, Pepco and Pepco Energy Services (now Generation, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have submitted multiple draft RI reports to the DOEE. In September 2019, Pepco and Generation issued a draft “final” RI report which DOEE approved and on October 4, 2019 released this document for review and comment by the public. The 45-day comment period ended on November 18, 2019 and a public meeting was held by Pepco on November 2, 2019. Pepco and Generation will proceed to develop a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the FS, and approval by the DOEE, by September 16, 2021.
DOEE will then prepare a Proposed Plan and issue a Record of Decision identifying any further response actions determined to be necessary, after considering public comment on the Proposed Plan. PHI, Pepco and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and the National Park Service have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. 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 and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road site RI/FS. In addition, the

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Note 14 — Commitments and Contingencies

District of Columbia Council directed DOEE to form an official advisory committee made up of members of federal, state and local environmental regulators, community and environmental groups and various academic and technical experts to provide guidance and support to DOEE as the project progressed. This group, called the Anacostia Leadership Council, has met regularly since it was formed. Pepco has participated in the Consultative Working Group. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing.
Pepco has determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best estimate of its share of those costs based on DOEE’s stated position following a series of meetings attended by representatives from the Anacostia Leadership Council and the Consultative Working Group. On December 27, 2019, DOEE released for review and comment by the public a Focused Feasibility Study (FFS) and a Proposed Plan (PP). The FFS and PP will be the basis for the Interim ROD, which is expected to be completed in September 2020. The FFS and PP are consistent with the DOEE’s stated position to follow an adaptive management approach which will allow several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion. Pepco concluded that incremental exposure remains reasonably possible, however management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. The Natural Resource Damages (NRD) assessment typically takes place following cleanup because cleanups sometimes also effectively restore affected natural resources. 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, Pepco cannot reasonably estimate the range of loss.
Litigation and Regulatory Matters
Asbestos Personal Injury Claims (Exelon and Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.
At June 30, 2020 and December 31, 2019, Exelon and Generation had recorded estimated liabilities of approximately $92 million and $83 million, respectively, in total for asbestos-related bodily injury claims. As of June 30, 2020, approximately $26 million of this amount related to 268 open claims presented to Generation, while the remaining $66 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.
It is reasonably possible that additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued could have a material, unfavorable impact on Exelon’s and Generation’s financial statements. However, management cannot reasonably estimate a range of loss beyond the amounts recorded.
City of Everett Tax Increment Financing Agreement (Exelon and Generation). On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts

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Note 14 — Commitments and Contingencies

Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. On January 8, 2020, the Massachusetts Superior Court affirmed the decision of the EACC denying the City's petition. The City had until March 9, 2020 to appeal the decision and did not. As a result, the decision is final and the case is resolved. It is reasonably possible that property taxes assessed in future periods, including those following the expiration of the TIF Agreement on June 30, 2020, could be material to Generation’s financial statements.
Subpoenas (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the United States Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date. The payments were recorded within Operating and maintenance expense in Exelon’s and ComEd’s Consolidated Statements of Operations and Comprehensive Income in the second quarter of 2020. The payments will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon.
Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ends with no charges being brought against Exelon.
The SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to the SEC investigation, as this contingency is neither probable nor reasonably estimable at this time. Management is currently unable to estimate a range of reasonably possible loss as this matter is subject to change.
Subsequent to Exelon announcing the receipt of the subpoenas, a putative class action lawsuit was filed against Exelon and certain officers of Exelon and ComEd alleging misrepresentations or omissions purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. In addition, a derivative shareholder lawsuit was filed against Exelon, its directors and certain officers of Exelon and ComEd alleging, among other things, breaches of fiduciary duties also purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. On July 28, 2020, plaintiff voluntarily dismissed this derivative action without prejudice to refile. Two additional putative class actions have been filed on July 27 and July 28, 2020. The first putative class action lawsuit against ComEd and Exelon has been filed in Illinois state court and seeks restitution and compensatory damages on behalf of ComEd customers. The second putative class action lawsuit against ComEd has been filed in federal court and alleges civil violations of federal racketeering laws. On August 2, 2020, plaintiffs in the federal lawsuit requested that ComEd waive service, which would make ComEd’s response due in October 2020. Both putative class action lawsuits relate to the conduct alleged in the DPA. No loss contingencies have been reflected in Exelon’s and ComEd’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time. Management is currently unable to estimate a range of reasonably possible loss due to the early stages of the lawsuits.
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

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Note 14 — Commitments and Contingencies

(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.
15. Changes in Accumulated Other Comprehensive Income (Exelon)
The following tables present changes in Exelon's AOCI, net of tax, by component:
Three Months Ended June 30, 2020
Losses on Cash Flow Hedges
 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
 
Foreign
Currency
Items
 
Total
Beginning balance
$
(3
)
 
$
(3,135
)
 
$
(35
)
 
$
(3,173
)
OCI before reclassifications
—

 
2

 
2

 
4

Amounts reclassified from AOCI
—

 
37

 
—

 
37

Net current-period OCI
—

 
39

 
2

 
41

Ending balance
$
(3
)
 
$
(3,096
)
 
$
(33
)
 
$
(3,132
)
Three Months Ended June 30, 2019
Losses on Cash Flow Hedges
 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates (b)
 
Total
Beginning balance
$
(2
)
 
$
(2,978
)
 
$
(31
)
 
$
(1
)
 
$
(3,012
)
OCI before reclassifications
—

 
(1
)
 
2

 
(1
)
 
—

Amounts reclassified from AOCI
—

 
22

 
—

 
—

 
22

Net current-period OCI
—

 
21

 
2

 
(1
)
 
22

Ending balance
$
(2
)
 
$
(2,957
)
 
$
(29
)
 
$
(2
)
 
$
(2,990
)
Six Months Ended June 30, 2020
Losses on Cash Flow Hedges
 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
 
Foreign
Currency
Items
 
Total
Beginning balance
$
(2
)
 
$
(3,165
)
 
$
(27
)
 
$
(3,194
)
OCI before reclassifications
(1
)
 
(5
)
 
(6
)
 
(12
)
Amounts reclassified from AOCI
—

 
74

 
—

 
74

Net current-period OCI
(1
)
 
69

 
(6
)
 
62

Ending balance
$
(3
)
 
$
(3,096
)
 
$
(33
)
 
$
(3,132
)

Six Months Ended June 30, 2019
Losses on Cash Flow Hedges
 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates (b)
 
Total
Beginning balance
$
(2
)
 
$
(2,960
)
 
$
(33
)
 
$
—

 
$
(2,995
)
OCI before reclassifications
—

 
(39
)
 
4

 
(2
)
 
(37
)
Amounts reclassified from AOCI
—

 
42

 
—

 
—

 
42

Net current-period OCI
—

 
3

 
4

 
(2
)
 
5

Ending balance
$
(2
)
 
$
(2,957
)
 
$
(29
)
 
$
(2
)
 
$
(2,990
)

125
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Changes in Accumulated Other Comprehensive Income

_________
(a)
AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 10 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
(b)
All amounts are net of noncontrolling interests.
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2020
 
2019
 
2020
 
2019
Pension and non-pension postretirement benefit plans:
 
 
 
 
 
 
 
Prior service benefit reclassified to periodic benefit cost
$
4

 
$
6

 
$
8

 
$
12

Actuarial loss reclassified to periodic benefit cost
(17
)
 
(13
)
 
(34
)
 
(26
)
Pension and non-pension postretirement benefit plans valuation adjustment
—

 
—

 
3

 
14


16. Variable Interest Entities (Exelon, Generation, PHI and ACE)
At June 30, 2020 and December 31, 2019, Exelon, Generation, PHI and ACE collectively consolidated several VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.
Consolidated VIEs
The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements of Exelon, Generation, PHI and ACE as of June 30, 2020 and December 31, 2019. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnote to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI and ACE.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
                                               
Note 16 — Variable Interest Entities



 
June 30, 2020
 
December 31, 2019
 
Exelon

Generation

PHI (a)
 
ACE
 
Exelon
 
Generation
 
PHI (a)
 
ACE
Cash and cash equivalents
$
114

 
$
114

 
$
—

 
$
—

 
$
163

 
$
163

 
$
—

 
$
—

Restricted cash and cash equivalents
105

 
102

 
3

 
3

 
88

 
85

 
3

 
3

Accounts receivable
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Customer
145

 
145

 
—

 
—

 
151

 
151

 
—

 
—

Other
38

 
38

 
—

 
—

 
39

 
39

 
—

 
—

Unamortized energy contract assets (b)
22

 
22

 
—

 
—

 
23

 
23

 
—

 
—

Inventories, net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Materials and supplies
236

 
236

 
—

 
—

 
227

 
227

 
—

 
—

Other current assets
675

 
671

 
4

 
—

 
32

 
31

 
1

 
—

Total current assets
1,335


1,328


7

 
3

 
723


719


4

 
3

Property, plant and equipment, net (c)
5,939

 
5,939

 
—

 
—

 
6,022

 
6,022

 
—

 
—

Nuclear decommissioning trust funds
2,642

 
2,642

 
—

 
—

 
2,741

 
2,741

 
—

 
—

Unamortized energy contract assets (b)
258

 
258

 
—

 
—

 
250

 
250

 
—

 
—

Other noncurrent assets
44

 
30

 
14

 
11

 
89

 
73

 
16

 
14

Total noncurrent assets
8,883


8,869


14

 
11

 
9,102


9,086


16

 
14

Total assets
$
10,218


$
10,197


$
21

 
$
14

 
$
9,825


$
9,805


$
20

 
$
17

Long-term debt due within one year
$
191

 
$
167

 
$
24

 
$
20

 
$
544

 
$
523

 
$
21

 
$
20

Accounts payable
71

 
71

 
—

 
—

 
106

 
106

 
—

 
—

Accrued expenses
60

 
60

 
—

 
—

 
70

 
70

 
—

 
—

Unamortized energy contract liabilities
6

 
6

 
—

 
—

 
8

 
8

 
—

 
—

Other current liabilities
6

 
6

 
—

 
—

 
3

 
3

 
—

 
—

Total current liabilities
334

 
310

 
24

 
20

 
731

 
710

 
21

 
20

Long-term debt
947

 
934

 
13

 
11

 
527

 
504

 
23

 
21

Asset retirement obligations (d)
2,182

 
2,182

 
—

 
—

 
2,128

 
2,128

 
—

 
—

Unamortized energy contract liabilities
1

 
1

 
—

 
—

 
1

 
1

 
—

 
—

Other noncurrent liabilities
80

 
80

 
—

 
—

 
89

 
89

 
—

 
—

Total noncurrent liabilities
3,210

 
3,197

 
13

 
11

 
2,745

 
2,722

 
23

 
21

Total liabilities
$
3,544

 
$
3,507

 
$
37

 
$
31

 
$
3,476

 
$
3,432

 
$
44

 
$
41

_________
(a)
Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
(b)
These are unrestricted assets to Exelon and Generation.
(c)
Exelon’s and Generation’s balances include unrestricted assets of $1 million and $20 million as of June 30, 2020 and December 31, 2019.
(d)
Exelon’s and Generation’s balances include liabilities with recourse of $2 million and $3 million as of June 30, 2020 and December 31, 2019, respectively.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
                                               
Note 16 — Variable Interest Entities



As of June 30, 2020 and December 31, 2019, Exelon's and Generation's consolidated VIEs consist of:
Consolidated VIE or VIE groups:
Reason entity is a VIE:
Reason Generation is primary beneficiary:
CENG - A joint venture between Generation and EDF. Generation has a 50.01% equity ownership in CENG. See additional discussion below.
Disproportionate relationship between equity interest and operational control as a result of NOSA described further below.
Generation conducts the operational activities.
EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. See additional discussion below.
Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.
Generation conducts the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by EGRP. Generation is a minority interest holder.
Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.
Generation conducts the operational activities.
Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&E through a PPA.
The PPA contract absorbs variability through a performance guarantee.
Generation conducts all activities.
Equity investment in distributed energy company - Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE (see Unconsolidated VIEs disclosure below).

Generation fully impaired this investment in the third quarter of 2019. See Note 11— Asset Impairments of the Exelon 2019 Form 10-K for additional information.
Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.
Generation conducts the operational activities.
NER - A bankruptcy remote, special purpose entity which is 100% owned by Generation, which purchases certain of Generation’s customer accounts receivable arising from the sale of retail electricity.

NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. See Note 5 - Accounts Receivable for additional information on the sale of receivables.

Equity capitalization is insufficient to support its operations.



Generation conducts all activities.

CENG - On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the NOSA pursuant to which Generation conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF.
EDF has the option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, Generation received notice of EDF's intention to exercise the put option to sell its interest in CENG to Generation and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period.
At this time, Generation cannot reasonably predict the ultimate purchase price that will be paid to EDF for its interest in CENG. The transaction will require approval by the NYPSC and the FERC. The process and regulatory approvals could take one to two years or more to complete.
See Note 2 - Mergers, Acquisitions and Dispositions of the Exelon 2019 Form 10-K for additional information regarding the Put Option Agreement with EDF.
Exelon and Generation, where indicated, provide the following support to CENG:
•
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 18 — Commitments and Contingencies of the Exelon 2019 Form 10-K for more details,

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
                                               
Note 16 — Variable Interest Entities



•
Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, 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.
EGRP - EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance and there is limited recourse related to Generation related to certain solar and wind entities.
In 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 12— Debt and Credit Agreements for additional information on ExGen Renewables IV.
As of June 30, 2020 and December 31, 2019, Exelon's, PHI's and ACE's consolidated VIE consists of:
Consolidated VIEs:
Reason entity is a VIE:
Reason ACE is the primary beneficiary:
ACE Funding - A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. Proceeds from the sale of each series of Transition Bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees.
ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ATF. The bondholders also have a variable interest for the investment made to purchase the Transition Bonds.
ACE controls the servicing activities.
Unconsolidated VIEs
Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (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.
As of June 30, 2020 and December 31, 2019, Exelon and Generation had significant unconsolidated variable interests in several VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
                                               
Note 16 — Variable Interest Entities



The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities:
 
June 30, 2020
 
December 31, 2019
 
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 
Total
 
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 
Total
Total assets(a)
$
705

 
$
417

 
$
1,122

 
$
636

 
$
443

 
$
1,079

Total liabilities(a)
172

 
227

 
399

 
33

 
227

 
260

Exelon's ownership interest in VIE(a)
—

 
168

 
168

 
—

 
191

 
191

Other ownership interests in VIE(a)
533

 
22

 
555

 
604

 
25

 
629

_________
(a)
These items represent amounts on the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. Exelon and Generation do not have any exposure to loss as they do not have a carrying amount in the equity investment VIEs as of June 30, 2020 and December 31, 2019.
As of June 30, 2020 and December 31, 2019, Exelon's and Generation's unconsolidated VIEs consist of:
Unconsolidated VIE groups:
Reason entity is a VIE:
Reason Generation is not the primary beneficiary:
Equity investments in distributed energy companies -

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

Generation fully impaired this investment in the third quarter of 2019. See Note 11— Asset Impairments of the Exelon 2019 Form 10-K for additional information.
Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.
Generation does not conduct the operational activities.
Energy Purchase and Sale agreements - Generation has several energy purchase and sale agreements with generating facilities.
PPA contracts that absorb variability through fixed pricing.
Generation does not conduct the operational activities.


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

Note 17 — Supplemental Financial Information

17. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
 
Operating revenues
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Three Months Ended June 30, 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating lease income
$
14

 
$
12

 
$
—

 
$
—

 
$
—

 
$
1

 
$
—

 
$
1

 
$
—

Variable lease income
80

 
79

 
—

 
—

 
—

 
1

 
—

 
1

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating lease income
$
14

 
$
12

 
$
—

 
$
—

 
$
—

 
$
1

 
$
—

 
$
1

 
$
—

Variable lease income
77

 
74

 
—

 
—

 
—

 
3

 
—

 
3

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating lease income
$
18

 
$
15

 
$
—

 
$
—

 
$
—

 
$
2

 
$
—

 
$
2

 
$
—

Variable lease income
149

 
148

 
—

 
—

 
—

 
1

 
—

 
1

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating lease income
$
18

 
$
15

 
$
—

 
$
—

 
$
—

 
$
2

 
$
—

 
$
2

 
$
—

Variable lease income
129

 
126

 
—

 
—

 
—

 
3

 
—

 
3

 
—


 
Taxes other than income taxes
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Three Months Ended June 30, 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility taxes(a)
$
196

 
$
23

 
$
55

 
$
31

 
$
18

 
$
69

 
$
64

 
$
5

 
$
—

Property
149

 
64

 
8

 
4

 
40

 
33

 
21

 
11

 
1

Payroll
61

 
28

 
7

 
4

 
4

 
7

 
2

 
1

 
1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility taxes(a)
$
209

 
$
32

 
$
55

 
$
30

 
$
21

 
$
71

 
$
67

 
$
4

 
$
—

Property
148

 
68

 
9

 
4

 
37

 
30

 
21

 
8

 
1

Payroll
61

 
30

 
7

 
4

 
4

 
7

 
2

 
1

 
1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility taxes(a)
$
414

 
$
49

 
$
114

 
$
62

 
$
44

 
$
145

 
$
133

 
$
10

 
$
1

Property
297

 
133

 
15

 
8

 
79

 
62

 
41

 
20

 
1

Payroll
125

 
60

 
14

 
8

 
9

 
15

 
4

 
2

 
2

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility taxes(a)
$
432

 
$
58

 
$
118

 
$
63

 
$
48

 
$
145

 
$
136

 
$
9

 
$
—

Property
296

 
138

 
15

 
8

 
75

 
60

 
43

 
16

 
1

Payroll
127

 
64

 
14

 
7

 
8

 
14

 
3

 
2

 
2

_________
(a)
Generation’s utility tax represents gross receipts tax related to its retail operations, and the Utility Registrants' utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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

Note 17 — Supplemental Financial Information

 
 
Other, Net
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Three Months Ended June 30, 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning-related activities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net realized income on NDT funds(a)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
$
30

 
$
30

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Non-regulatory agreement units
23

 
23

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Net unrealized gains on NDT funds
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
645

 
645

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Non-regulatory agreement units
452

 
452

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Regulatory offset to NDT fund-related activities(b)
(542
)
 
(542
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Decommissioning-related activities
608

 
608

 
—

 
—

 
—


—

 
—

 
—

 
—

AFUDC — Equity
26

 
—

 
8

 
4

 
6

 
8

 
6

 
1

 
1

Non-service net periodic benefit cost
14

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended June 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning-related activities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net realized income on NDT funds(a)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
$
77

 
$
77

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Non-regulatory agreement units
230

 
230

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Net unrealized (losses) gains on NDT funds
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
98

 
98

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Non-regulatory agreement units
(98
)
 
(98
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Regulatory offset to NDT fund-related activities(b)
(141
)
 
(141
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Decommissioning-related activities
166

 
166

 
—

 
—

 
—


—


—

 
—

 
—

AFUDC — Equity
21

 
—

 
4

 
3

 
5

 
9

 
6

 
1

 
2

Non-service net periodic benefit cost
5

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—


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

Note 17 — Supplemental Financial Information

 
Other, net
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Six Months Ended June 30, 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning-related activities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net realized income on NDT funds(a)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
$
77

 
$
77

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Non-regulatory agreement units
104

 
104

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Net unrealized gains on NDT funds
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
(287
)
 
(287
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Non-regulatory agreement units
(253
)
 
(253
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Regulatory offset to NDT fund-related activities(b)
167

 
167

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Decommissioning-related activities
(192
)
 
(192
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

AFUDC — Equity
49

 
—

 
14

 
7

 
10

 
17

 
13

 
2

 
2

Non-service net periodic benefit cost
24

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning-related activities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net realized income on NDT funds(a)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
$
131

 
$
131

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Non-regulatory agreement units
283

 
283

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Net unrealized losses on NDT funds
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
476

 
476

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Non-regulatory agreement units
182

 
182

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Regulatory offset to NDT fund-related activities(b)
(487
)
 
(487
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Decommissioning-related activities
585

 
585

 
—

 
—

 
—

 
—


—

 
—

 
—

AFUDC — Equity
43

 
—

 
9

 
6

 
10

 
18

 
12

 
2

 
4

Non-service net periodic benefit cost
10

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

_________
(a)
Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
(b)
Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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

Note 17 — Supplemental Financial Information

Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
 
Depreciation, amortization and accretion
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Six Months Ended June 30, 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, plant and equipment(a)
$
1,715

 
$
577

 
$
458

 
$
159

 
$
195

 
$
289

 
$
126

 
$
76

 
$
69

Amortization of regulatory assets(a)
277

 
—

 
89

 
14

 
77

 
96

 
60

 
18

 
17

Amortization of intangible assets, net(a)
31

 
27

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Amortization of energy contract assets and liabilities(b)
12

 
10

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Nuclear fuel(c)
459

 
459

 
—

 
—

 
—

 
—

 
—

 
—

 
—

ARO accretion(d)
247

 
247

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total depreciation, amortization and accretion
$
2,741


$
1,320


$
547


$
173


$
272

 
$
385

 
$
186


$
94


$
86

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, plant and equipment(a)
$
1,859

 
$
789

 
$
439

 
$
149

 
$
173

 
$
266

 
$
117

 
$
71

 
$
57

Amortization of regulatory assets(a)
266

 
—

 
69

 
15

 
79

 
103

 
69

 
20

 
14

Amortization of intangible assets, net(a)
29

 
25

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Amortization of energy contract assets and liabilities(b)
5

 
5

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Nuclear fuel(c)
513

 
513

 
—

 
—

 
—

 
—

 
—

 
—

 
—

ARO accretion(d)
250

 
248

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total depreciation, amortization and accretion
$
2,922


$
1,580


$
508


$
164


$
252

 
$
369

 
$
186


$
91


$
71

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

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

Note 17 — Supplemental Financial Information

 
Other non-cash operating activities
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Six Months Ended June 30, 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and non-pension postretirement benefit costs
$
203

 
$
58

 
$
57

 
$
3

 
$
31

 
$
35

 
$
7

 
$
4

 
$
7

Provision for uncollectible accounts
92

 
13

 
17

 
29

 
10

 
22

 
12

 
8

 
2

Other decommissioning-related activity(a)
(60
)
 
(60
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Energy-related options(b)
27

 
27

 
—

 
—

 
—

 
—

 
—

 
—

 
—

True-up adjustments to decoupling mechanisms and formula rates(c)

55

 
—

 
13

 
(5
)
 
—

 
47

 
(2
)
 
24

 
25

Long-term incentive plan
(10
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Amortization of operating ROU asset
112

 
80

 
1

 
—

 
15

 
14

 
3

 
4

 
2

Deferred Prosecution Agreement payments(d)
200

 
—

 
200

 
—

 
—

 
—

 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and non-pension postretirement benefit costs
$
212

 
$
62

 
$
47

 
$
5

 
$
29

 
$
48

 
$
12

 
$
8

 
$
8

Provision for uncollectible accounts
45

 
12

 
16

 
10

 
4

 
3

 
2

 
1

 
—

Other decommissioning-related activity(a)
(260
)
 
(261
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Energy-related options(b)
43

 
43

 
—

 
—

 
—

 
—

 
—

 
—

 
—

True-up adjustments to decoupling mechanisms and formula rates(e)

14

 
—

 
24

 
—

 
—

 
(10
)
 
(8
)
 
(2
)
 
—

Long-term incentive plan
35

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Amortization of operating ROU asset
115

 
78

 
1

 
—

 
15

 
17

 
4

 
5

 
2

_______
(a)
Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 9 — Asset Retirement Obligations of the Exelon 2019 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 to results of operations.
(c)
For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency and transmission formula rates. For BGE, Pepco and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO and ACE, reflects the change in regulatory assets and liabilities associated with their transmission formula rates. See Note 2 — Regulatory Matters for additional information.
(d)
See Note 14 — Commitments and Contingencies for additional information related to the Deferred Prosecution Agreement.
(e)
For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution and energy efficiency formula rates. For Pepco and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms. See Note 2 — Regulatory Matters for additional information.


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

Note 17 — Supplemental Financial Information

The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
June 30, 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
2,129

 
$
483

 
$
403

 
$
380

 
$
195

 
$
39

 
$
19

 
$
6

 
$
8

Restricted cash
373

 
153

 
155

 
7

 
1

 
36

 
33

 
—

 
3

Restricted cash included in other long-term assets
178

 
—

 
166

 
—

 
—

 
11

 
—

 
—

 
11

Total cash, cash equivalents and restricted cash
$
2,680

 
$
636

 
$
724

 
$
387

 
$
196

 
$
86

 
$
52

 
$
6

 
$
22

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
587

 
$
303

 
$
90

 
$
21

 
$
24

 
$
131

 
$
30

 
$
13

 
$
12

Restricted cash
358

 
146

 
150

 
6

 
1

 
36

 
33

 
—

 
2

Restricted cash included in other long-term assets
177

 
—

 
163

 
—

 
—

 
14

 
—

 
—

 
14

Total cash, cash equivalents and restricted cash
$
1,122

 
$
449

 
$
403

 
$
27

 
$
25

 
$
181

 
$
63

 
$
13

 
$
28

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
June 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
735

 
$
575

 
$
65

 
$
20

 
$
8

 
$
54

 
$
18

 
$
3

 
$
4

Restricted cash
252

 
122

 
77

 
6

 
1

 
37

 
34

 
1

 
2

Restricted cash included in other long-term assets
191

 
—

 
174

 
—

 
—

 
17

 
—

 
—

 
17

Total cash, cash equivalents and restricted cash
$
1,178

 
$
697

 
$
316

 
$
26

 
$
9

 
$
108

 
$
52

 
$
4

 
$
23

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
1,349

 
$
750

 
$
135

 
$
130

 
$
7

 
$
124

 
$
16

 
$
23

 
$
7

Restricted cash
247

 
153

 
29

 
5

 
6

 
43

 
37

 
1

 
4

Restricted cash included in other long-term assets
185

 
—

 
166

 
—

 
—

 
19

 
—

 
—

 
19

Total cash, cash equivalents and restricted cash
$
1,781

 
$
903

 
$
330

 
$
135

 
$
13

 
$
186

 
$
53

 
$
24

 
$
30

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2019 Form 10-K.

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

Note 17 — Supplemental Financial Information

Supplemental Balance Sheet Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
 
Accrued expenses
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
June 30, 2020
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Compensation-related accruals(a)
$
744

 
$
277

 
$
135

 
$
50

 
$
52

 
$
92

 
$
32

 
$
18

 
$
14

Taxes accrued
396

 
229

 
61

 
2

 
19

 
73

 
54

 
5

 
8

Interest accrued
357

 
53

 
119

 
37

 
46

 
51

 
25

 
8

 
13

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Compensation-related accruals(a)
$
1,052

 
$
422

 
$
171

 
$
58

 
$
78

 
$
101

 
$
28

 
$
19

 
$
15

Taxes accrued
414

 
222

 
83

 
3

 
26

 
117

 
90

 
14

 
8

Interest accrued
337

 
65

 
110

 
37

 
46

 
49

 
23

 
8

 
12

_________
(a)
Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
18. Related Party Transactions (All Registrants)
Operating revenues from affiliates
Generation
The following table presents Generation’s Operating revenues from affiliates, which are primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
2020
 
2019
 
2020

2019
Operating revenues from affiliates:
 
 
 
 
 
 
 
ComEd(a)(b)
$
80

 
$
89

 
$
170

 
$
183

PECO(c)
41

 
35

 
78

 
80

BGE(d)
70

 
57

 
169

 
133

PHI
78

 
69

 
182

 
170

Pepco(e)
60

 
52

 
139

 
122

DPL(f)
16

 
12

 
38

 
35

ACE(g)
2

 
5

 
5

 
13

Other
2

 
2

 
2

 
3

Total operating revenues from affiliates (Generation)
$
271

 
$
252

 
$
601

 
$
569

__________
(a)
Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.
(b)
For the three and six months ended June 30, 2020 , respectively, ComEd’s Purchased power from Generation of $84 million and $181 million is recorded as Operating revenues from ComEd of $80 million and $170 million and as Purchased power and fuel from ComEd of $4 million and $11 million at Generation. For the three and six months ended June 30, 2019 , respectively, ComEd’s Purchased power from Generation of $90 million and $187 million is recorded as Operating revenues from ComEd of $89 million and $183 million and as Purchased power and fuel from ComEd of $1 million and $4 million at Generation.
(c)
Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs.

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

Note 18 — Related Party Transactions


(d)
Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.
(e)
Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.
(f)
Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.
(g)
Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.
PHI
PHI’s Operating revenues from affiliates are primarily with BSC for services that PHISCO provides to BSC.
Operating and maintenance expense from affiliates
The Registrants receive a variety of corporate support services from BSC. Pepco, DPL and ACE also receive corporate support services from PHISCO. See Note 1 - Significant Accounting Policies for additional information regarding BSC and PHISCO.
The following table presents the service company costs allocated to the Registrants:
 
 
Operating and maintenance from affiliates
 
Capitalized costs
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2020
 
2019
 
2020
 
2019
 
2020
 
2019
 
2020
 
2019
Exelon
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
BSC
 
 
 
 
 
 
 
 
 
$
129

 
$
132

 
$
242

 
$
232

PHISCO
 
 
 
 
 
 
 
 
 
16

 
19

 
30

 
40

Generation
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   BSC
 
$
133

 
$
148

 
$
273

 
$
297

 
14

 
14

 
25

 
26

ComEd
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   BSC
 
67

 
60

 
138

 
122

 
41

 
36

 
83

 
61

PECO
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   BSC
 
36

 
37

 
73

 
74

 
18

 
24

 
33

 
46

BGE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   BSC
 
40

 
39

 
82

 
77

 
30

 
38

 
58

 
59

PHI
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   BSC
 
35

 
34

 
72

 
66

 
26

 
20

 
43

 
40

   PHISCO
 
—

 
—

 
—

 
—

 
16

 
19

 
30

 
40

Pepco
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   BSC
 
20

 
22

 
41

 
43

 
9

 
9

 
15

 
17

   PHISCO
 
32

 
31

 
62

 
63

 
7

 
9

 
13

 
17

DPL
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   BSC
 
13

 
13

 
26

 
26

 
9

 
6

 
14

 
11

   PHISCO
 
25

 
25

 
49

 
50

 
5

 
5

 
9

 
12

ACE
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   BSC
 
11

 
11

 
21

 
21

 
8

 
4

 
12

 
8

   PHISCO
 
23

 
22

 
44

 
45

 
4

 
5

 
8

 
11



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

Note 18 — Related Party Transactions


Current Receivables from/Payables to affiliates
The following tables present current receivables from affiliates and current payables to affiliates:
June 30, 2020
 
 
Receivables from affiliates:
 
 
Payables to affiliates:
 
Generation
 
ComEd
 
PECO
 
BGE
 
Pepco
 
DPL
 
ACE
 
BSC
 
PHISCO
 
Other
 
Total
Generation
 
 
 
$
16

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
75

 
$
—

 
$
22

 
$
113

ComEd
 
$
49

(a)
 
 
—

 
—

 
—

 
—

 
—

 
42

 
—

 
8

 
99

PECO
 
20

 
6

 
 
 
—

 
—

 
1

 
—

 
25

 
—

 
5

 
57

BGE
 
11

 
—

 
—

 
 
 
—

 
—

 
—

 
28

 
—

 
2

 
41

PHI
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
4

 
—

 
10

 
14

Pepco
 
15

 
—

 
—

 
—

 


 
—

 
—

 
12

 
18

 
1

 
46

DPL
 
3

 
—

 
—

 
—

 
2

 


 
—

 
10

 
11

 
1

 
27

ACE
 
11

 
—

 
—

 
—

 
—

 
—

 
 
 
8

 
11

 
1

 
31

Other
 
9

 
1

 
—

 
—

 
—

 
—

 
1

 
—

 
—

 
 
 
11

Total
 
$
118

 
$
23

 
$
—

 
$
—

 
$
2

 
$
1

 
$
1

 
$
204

 
$
40

 
$
50

 
$
439

December 31, 2019
 
 
Receivables from affiliates:
 
 
Payables to affiliates:
 
Generation
 
ComEd
 
PECO
 
BGE
 
Pepco
 
DPL
 
ACE
 
BSC
 
PHISCO
 
Other
 
Total
Generation
 
 
 
$
27

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
67

 
$
—

 
$
23

 
$
117

ComEd
 
$
78

(a)
 
 
—

 
—

 
—

 
—

 
—

 
54

 
—

 
8

 
140

PECO
 
27

 
—

 


 
—

 
—

 
—

 
—

 
25

 
—

 
3

 
55

BGE
 
28

 
—

 
—

 
 
 
—

 
—

 
—

 
34

 
—

 
4

 
66

PHI
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
4

 
—

 
10

 
14

Pepco
 
34

 
—

 
—

 
—

 
 
 
—

 
—

 
16

 
15

 
1

 
66

DPL
 
7

 
—

 
—

 
—

 
—

 


 
3

 
10

 
11

 
1

 
32

ACE
 
7

 
—

 
—

 
—

 
—

 
—

 
 
 
7

 
10

 
1

 
25

Other
 
9

 
1

 
1

 
1

 
—

 
—

 
1

 
—

 
—

 
 
 
13

Total
 
$
190

 
$
28

 
$
1

 
$
1

 
$
—

 
$
—

 
$
4

 
$
217

 
$
36

 
$
51

 
$
528

__________
(a)
As of June 30, 2020 and December 31, 2019, Generation had a contract liability with ComEd for $7 million and $37 million, respectively, that was included in Other current liabilities on Generation’s Consolidated Balance Sheets. At June 30, 2020 and December 31, 2019, ComEd had a Current Payable to Generation of $42 million and $41 million, respectively, on its Consolidated Balance Sheets, which consisted of Generation’s Current Receivable from ComEd, partially offset by Generation’s contract liability with ComEd.
Borrowings from Exelon/PHI 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. Generation, ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL and ACE participate in the PHI intercompany money pool.
Noncurrent Receivables from/Payables to affiliates

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

Note 18 — Related Party Transactions


Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information.
The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation:
 
June 30, 2020
 
December 31, 2019
ComEd
$
2,374

 
$
2,622

PECO
376

 
480

Other
1

 
1

Total:
$
2,751

 
$
3,103


Long-term debt to financing trusts
The following table presents Long-term debt to financing trusts:
 
June 30, 2020
 
December 31, 2019
 
Exelon
 
ComEd
 
PECO
 
Exelon
 
ComEd
 
PECO
ComEd Financing III
$
206

 
$
205

 
$
—

 
$
206

 
$
205

 
$
—

PECO Trust III
81

 
—

 
81

 
81

 
—

 
81

PECO Trust IV
103

 
—

 
103

 
103

 
—

 
103

Total
$
390

 
$
205

 
$
184

 
$
390

 
$
205

 
$
184


Long-term debt to affiliates
In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate.
19. Subsequent Events (Exelon, PHI, Pepco, DPL, and ACE)
Sale of Transmission Tower Attachment Agreements
On July 1, 2020, Pepco, DPL and ACE each entered into an agreement to sell a 60% undivided interest in their respective portfolios of transmission tower attachment agreements with telecommunications companies to an unrelated owner and manager of communication infrastructure (the Buyer). As part of the transaction, the Buyer will manage the day-to-day operations of the jointly-owned agreements with telecommunications companies for a period of 35 years. In addition, for an initial period of three years for two, two-year extensions that are subject to certain conditions, the Buyer has the exclusive right to enter into new agreements with telecommunications companies and to receive a 30% undivided interest in those new agreements. As a result of the transaction, Pepco, DPL, and ACE received cash and recorded liabilities of $98 million, $13 million, and $13 million, respectively, in the third quarter of 2020.

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Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
(Dollars in millions except per share data, unless otherwise noted)
Exelon
Executive Overview
Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.
Exelon has eleven reportable segments consisting of Generation’s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL and ACE. See Note 1 — Significant Accounting Policies and Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.
COVID-19. The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. The Registrants provide a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to the virus. The Registrants have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities. We have implemented work from home policies where appropriate, and imposed travel limitations on our employees. In addition, the Registrants have updated existing business continuity plans in the context of this pandemic.
The Registrants continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers.
There have been no changes in internal control over financial reporting to date in 2020 as of result of COVID-19 that materially affected, or are reasonably likely to materially affect, any of the Registrants’ internal control over financial reporting. See Item 4. Controls and Procedures for additional information.
The estimated impact to Generation’s and the Utility Registrants’ Net income as a result of COVID-19 is approximately $100 million and $50 million, respectively, for the three and six months ended June 30, 2020 and primarily reflects the impact of reduction in load, incremental credit loss expense and direct costs related to COVID-19 as further discussed below.
Unfavorable economic conditions due to COVID-19 have impacted the demand for electricity and natural gas in the second quarter of 2020 and are expected to continue to impact demand in the second half of 2020. Commercial and Industrial customer demand has experienced a notable decrease, while residential demand has slightly increased. Generation and the Utility Registrants estimate a net decrease in Net income due to reduction in load of $50 to $100 million and $10 to $25 million, respectively, in the second half of 2020. Generation and the Utility Registrants load forecasts are highly dependent on many factors including, but not limited to, the duration of remaining restrictions and the speed and strength of the economic recovery. A 1% change in load would result in the following change in Net income in the second half of 2020:

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Generation’s Net Income
Utility Registrants’ Net Income
Commercial & Industrial Customers
$
8

$
4

Residential Customers
4

4

Generation temporarily suspended interruption of service for all retail residential customers for non-payment and temporarily ceased new late payment fees for all retail customers from March to May of 2020. Starting in March of 2020, the Utility Registrants also temporarily suspended customer disconnections for non-payment and temporarily ceased new late payment fees for all customers and restored service to customers upon request who were disconnected in the last twelve months. These measures were in place through July 1, 2020 for DPL Delaware and July 15, 2020 for ACE and are currently expected to continue through August 31, 2020 for ComEd, September 1, 2020 for BGE, Pepco Maryland and DPL Maryland, October 9, 2020 for Pepco District of Columbia and until further notice for PECO. As a result of such measures, the Registrants expect an increase in Customer allowance for credit losses for the year ending December 31, 2020. Generation estimates a decrease in Net income due to an increase in credit loss expense of $15 to $50 million in the second half of 2020. The Utility Registrants do not expect a material decrease in Net income for the year ending December 31, 2020. Typically, they recover credit loss expense through rate required programs or distribution base rate cases. For those jurisdictions without an existing rate required program to recover credit loss expense, the Utility Registrants are pursuing strategies with their respective commissions to recover incremental costs being incurred as a result of COVID-19. During April, May, and July of 2020, the MDPSC, the DCPSC, the DPSC, and the NJBPU issued orders authorizing the creation of regulatory assets to track incremental COVID-19 related costs. Also, in May of 2020, the PAPUC issued a Secretarial Letter authorizing the creation of regulatory assets to track incremental credit loss expense related to COVID-19. Such orders and the Secretarial Letter will allow for assessment of recovery of those costs in future distribution base rate cases. ComEd and ACE have existing mechanisms for recovery of credit loss expense. The other Utility Registrants are assessing the regulatory facts and circumstances and expect to record regulatory assets in the second half of 2020 for the incremental credit loss expense related to COVID-19, including the expense recorded in the second quarter of 2020. However, the timing and amount of the recovery offset of the increase in credit loss expense could extend beyond 2020, which could have a negative impact on Net income for the year ending December 31, 2020.

The Registrants have also incurred direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of their employees. Such costs are excluded from Adjusted (non-GAAP) Operating Earnings.

To offset part of the unfavorable impacts from reduction in load, increase in credit loss expense and direct costs related to COVID-19, the Registrants identified and are pursuing approximately $250 million in cost savings across Generation and the Utility Registrants.

The Registrants rely on the capital markets for publicly offered debt as well as the commercial paper markets to meet their financial commitments and short-term liquidity needs. As a result of the disruptions in the commercial paper markets in March of 2020, Generation borrowed $1.5 billion on its revolving credit facility to refinance commercial paper, which Generation repaid on April 3, 2020. Generation also entered into two short-term loan agreements in March of 2020 for an aggregate of $500 million. On April 8, 2020, Generation received approximately $500 million in cash after entering into an accounts receivable financing arrangement. On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility to be used as an additional source of short-term liquidity. In addition, to date in 2020, the Registrants have issued long-term debt of $5.1 billion, of which $4.0 billion was issued in the period of April to July of 2020. The Registrants accelerated the timing of a number of planned debt issuances resulting in the $4.0 billion issued in the period of April to July of 2020 and the Registrants have now completed their planned long-term debt issuances for the 2020 year. See Liquidity and Capital Resources, Note 12 - Debt and Credit Agreements, and Note 5 - Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.

The Registrants assessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded to date in 2020. Certain assumptions are highly sensitive to changes. Changes in significant assumptions could potentially result in future impairments, which could be material.

This is an evolving situation that could lead to extended disruption of economic activity in our markets. The Registrants will continue to monitor developments affecting our workforce, our customers and our suppliers and we will take additional precautions that we determine are necessary in order to mitigate the impacts. The extent to which

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COVID-19 may impact the Registrants’ ability to operate their generating and transmission and distribution assets, the ability to access capital markets, and results of operations, including demand for electricity and natural gas, will depend on the spread and proliferation of COVID-19 around the world and future developments, which are highly uncertain and cannot be predicted at this time.
Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the three and six months ended June 30, 2020 compared to the same period in 2019. For additional information regarding the financial results for the three and six months ended June 30, 2020 and 2019 see the discussions of Results of Operations by Registrant.
 
Three Months Ended June 30,
 
Favorable (unfavorable) variance
 
Six Months Ended June 30,
 
Favorable (unfavorable) variance
 
2020
 
2019
 
 
2020
 
2019
 
Exelon
521

 
484

 
$
37

 
$
1,103

 
$
1,391

 
$
(288
)
Generation
476

 
108

 
368

 
521

 
472

 
49

ComEd
(61
)
 
186

 
(247
)
 
107

 
344

 
(237
)
PECO
39

 
102

 
(63
)
 
178

 
270

 
(92
)
BGE
39

 
45

 
(6
)
 
219

 
206

 
13

PHI
94

 
106

 
(12
)
 
202

 
223

 
(21
)
Pepco
57

 
64

 
(7
)
 
109

 
119

 
(10
)
DPL
19

 
30

 
(11
)
 
64

 
83

 
(19
)
ACE
18

 
14

 
4

 
31

 
24

 
7

Other(a)
(66
)
 
(63
)
 
(3
)
 
(124
)
 
(124
)
 
—

__________
(a)
Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities.
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income attributable to common shareholders increased by $37 million and diluted earnings per average common share increased to $0.53 in 2020 from $0.50 in 2019 primarily due to:
•
Higher net unrealized and realized gains on NDT funds;
•
Higher mark-to-market gains;
•
Lower operating and maintenance expense primarily due to lower contracting costs at Generation; and
•
Favorable weather conditions at PECO and DPL Delaware.
The increases were partially offset by:
•
Payments that ComEd will make under the Deferred Prosecution Agreement.  See Note 14 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information;
•
Lower capacity revenue;
•
Reduction in load due to COVID-19 at Generation;
•
Higher storm costs related to the June 2020 storms at PECO;
•
Higher credit loss expense that includes the impacts of COVID-19 at Generation, PECO, Pepco and DPL;
•
COVID-19 direct costs; and
•
Lower electric distribution earnings at ComEd primarily due to distribution formula rate timing.

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Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income attributable to common shareholders decreased by $288 million and diluted earnings per average common share decreased to $1.13 in 2020 from $1.43 in 2019 primarily due to:
•
Payments that ComEd will make under the Deferred Prosecution Agreement.  See Note 14 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information;
•
Higher net unrealized and realized losses on NDT funds;
•
Lower capacity revenue;
•
Reduction in load due to COVID-19 at Generation;
•
Higher nuclear outage days;
•
Higher storm costs related to the June 2020 storms at PECO;
•
Higher credit loss expense that includes the impacts of COVID-19 at Generation, PECO, Pepco, and DPL;
•
COVID-19 direct costs;
•
Unfavorable weather conditions at PECO and ACE; and
•
Lower allowed electric distribution ROE due to a decrease in treasury rates.
The decreases were partially offset by:
•
Higher mark-to-market gains;
•
Lower operating and maintenance expense primarily due to previous cost management programs and lower contracting costs at Generation;
•
The approval of the New Jersey ZEC program in the second quarter of 2019;
•
An income tax settlement at Generation; and
•
Regulatory rate increases at BGE and ACE.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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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, 2020 compared to the same period in 2019.
 
Three Months Ended June 30,
 
2020
 
2019
(All amounts in millions after tax)
 
 
Earnings per
Diluted Share
 
 
 
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders
$
521

 
$
0.53

 
$
484

 
$
0.50

Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $18 and $22, respectively)
(51
)
 
(0.05
)
 
68

 
0.07

Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $275 and $28, respectively)(a)
(305
)
 
(0.31
)
 
52

 
0.05

Asset Impairments (net of taxes of $7 and $1, respectively)(b)
19

 
0.02

 
1

 
—

Plant Retirements and Divestitures (net of taxes of $2 and $37, respectively)(c)
7

 
0.01

 
(24
)
 
(0.02
)
Cost Management Program (net of taxes of $3 and $1, respectively)(d)
6

 
0.01

 
6

 
0.01

Litigation Settlement Gain (net of taxes of $7)
—

 
—

 
(19
)
 
(0.02
)
Change in Environmental Liabilities (net of taxes of $0)
1

 
—

 
—

 
—

COVID-19 Direct Costs (net of taxes of $10)(e)
27

 
0.03

 
—

 
—

Deferred Prosecution Agreement Payments (net of taxes of $0)(f)
200

 
0.20

 
—

 
—

Income Tax-Related Adjustments (entire amount represents tax expense)
5

 
0.01

 
—

 
—

Noncontrolling Interests (net of taxes of $20 and $3, respectively)(g)
104

 
0.11

 
15

 
0.02

Adjusted (non-GAAP) Operating Earnings
$
536

 
$
0.55

 
$
583

 
$
0.60


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Six Months Ended June 30,
 
2020
 
2019
(All amounts in millions after tax)
 
 
Earnings per
Diluted Share
 
 
 
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders
$
1,103

 
$
1.13

 
$
1,391

 
$
1.43

Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $50 and $34, respectively)
(146
)
 
(0.15
)
 
98

 
0.10

Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $130 and $133, respectively)(a)
180

 
0.18

 
(142
)
 
(0.15
)
Asset Impairments (net of taxes of $7 and $2, respectively)(b)
21

 
0.02

 
6

 
0.01

Plant Retirements and Divestitures (net of taxes of $6 and $32, respectively)(c)
20

 
0.02

 
(4
)
 
—

Cost Management Program (net of taxes of $6 and $7, respectively)(d)
17

 
0.02

 
16

 
0.02

Litigation Settlement Gain (net of taxes of $7)
—

 
—

 
(19
)
 
(0.02
)
Change in Environmental Liabilities (net of taxes of $0)
1

 
—

 
—

 
—

COVID-19 Direct Costs (net of taxes of $10)(e)
27

 
0.03

 
—

 
—

Deferred Prosecution Agreement Payments (net of taxes of $0)(f)
200

 
0.20

 
—

 
—

Income Tax-Related Adjustments (entire amount represents tax expense)
4

 
—

 
—

 
—

Noncontrolling Interests (net of taxes of $10 and $15, respectively)(g)
(40
)
 
(0.04
)
 
82

 
0.08

Adjusted (non-GAAP) Operating Earnings
$
1,387

 
$
1.42

 
$
1,429

 
$
1.47

__________
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 2020 and 2019 ranged from 26.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 47.4% and 35.1% for the three months ended June 30, 2020 and 2019, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 41.9% and 48.4% for the six months ended June 30, 2020 and 2019, respectively.

(a)
Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.
(b)
Reflects an impairment at ComEd related to the acquisition of transmission assets and the impairment of certain wind assets at Generation.
(c)
In 2019, primarily reflects net realized gains related to Oyster Creek's NDT fund investments in conjunction with the Holtec sale on July 1, 2019 and a gain on the sale of certain wind assets, partially offset by accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility. In 2020, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of certain fossil sites.
(d)
Primarily represents reorganization costs related to cost management programs.
(e)
Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.
(f)
Reflects the payments that ComEd will make under the Deferred Prosecution Agreement. See Note 14 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
(g)
Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units.

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Significant 2020 Transactions and Developments
Deferred Prosecution Agreement
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into ComEd’s lobbying activities in the State of Illinois. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the United States Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date. The payments will not be recovered in rates or charged to customers, and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon.
Utility Rates and Base Rate Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2020. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Requested Revenue Requirement (Decrease) Increase
Approved Revenue Requirement (Decrease) Increase
Approved ROE
Approval Date
Rate Effective Date
ComEd - Illinois (Electric)
April 8, 2019
$
(6
)
$
(17
)
8.91
%
December 4, 2019
January 1, 2020
DPL - Maryland (Electric)
December 5, 2019 (amended April 23, 2020)
17

12

9.60
%
July 14, 2020
July 16, 2020

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Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Requested Revenue Requirement (Decrease) Increase
Requested ROE
Expected Approval Timing
ComEd - Illinois (Electric)
April 16, 2020
$
(11
)
8.38
%
Fourth quarter of 2020
BGE - Maryland (Electric and Natural Gas)
May 15, 2020
235

10.1
%
Fourth quarter of 2020
Pepco - District of Columbia (Electric)
May 30, 2019 (amended June 1, 2020)
136

9.7
%
Fourth quarter of 2020
DPL - Delaware (Natural Gas)
February 21, 2020 (amended March 17, 2020)
9

10.3
%
First quarter of 2021
DPL - Delaware (Electric)
March 6, 2020 (amended April 16, 2020)
24

10.3
%
Second quarter of 2021
Transmission Formula Rates
Transmission Formula Rate (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or before May 15 and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd, BGE, DPL and ACE is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for Pepco is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense and accumulated deferred income taxes. The update for ComEd, BGE, DPL and ACE also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The update for PECO and Pepco also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2020, the following total increases/(decreases) were included in ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:
Registrant
Initial Revenue Requirement Increase (Decrease)
Annual Reconciliation Decrease
Total Revenue Requirement Increase (Decrease)
Allowed Return on Rate Base
Allowed ROE
ComEd
$
18

$
(4
)
$
14

8.17
%
11.50
%
PECO
5

(28
)
(23
)
7.47
%
10.35
%
BGE
16

(3
)
4

7.26
%
10.50
%
Pepco
2

(46
)
(44
)
7.81
%
10.50
%
DPL
(4
)
(40
)
(44
)
7.20
%
10.50
%
ACE
5

(25
)
(20
)
7.40
%
10.50
%

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Sales of Customer Accounts Receivable
On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by Generation, entered into an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain customer accounts receivables. Generation received approximately $500 million of cash in accordance with the initial sale of approximately $1.2 billion receivables. See Note 5 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
Other Key Business Drivers and Management Strategies
The following discussion of other key business driver and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the Registrants' combined 2019 Form 10-K and Note 14 — Commitments and Contingencies to the Consolidated Financial Statements in this report for additional information on various environmental matters.
Power Markets
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 from imports of uranium products, alleging that these imports threaten national security.
The United States Nuclear Fuel Working Group ("Working Group") report was made public on April 23, 2020. The Working Group report states that nuclear power is intrinsically tied to national security, and promises that the U.S. government will take bold actions to strengthen all parts of the nuclear fuel industry in the U.S. It recommends the Agreement Suspending the Antidumping Investigation on Uranium from the Russian Federation (the “Russian Suspension Agreement”) be extended and to consider reducing the amount of Russian imports of nuclear fuel. The Russian Suspension Agreement is the historical resolution of a 1991 DOC investigation that found that the Russians had been selling or “dumping” cheap uranium products into the U.S. The Russian Suspension Agreement has been amended several times in the intervening years to allow Russia to supply limited amounts of uranium products into the U.S.  It was set to expire at the end of 2020, but the U.S. government has expressed interest in continuing the limitations on Russian imports by renegotiating the Russian Suspension Agreement.
The Working Group report should be viewed as policy recommendations that may be implemented by executive agencies, congress and or regulatory bodies. Negotiations between the DOC and the Russians on an extension of the Russian Suspension Agreement are in progress at this time, and may result in a reduction in the amount of uranium that can be imported from Russia, which may have the effect of reducing the diversity of supply available to Exelon for uranium, enrichment and conversion services purchases. Exelon and Generation cannot currently predict the outcome of the policy changes recommended by the Working Group.
Hedging Strategy
Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. As of June 30, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 98%-101% and 76%-79% for 2020 and 2021, respectively. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.
Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 60% of Generation’s uranium concentrate requirements from

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2020 through 2024 are supplied by three suppliers. 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.
See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and Item 3. Quantitative and Qualitative Disclosures about Market Risk for additional information.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Environmental Legislative and Regulatory Developments
Air Quality
Mercury and Air Toxics Standards Rule (MATS). On December 16, 2011, the EPA signed a final rule, known as MATS, to reduce emissions of hazardous air pollutants from power plants. MATS requires coal-fired power 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. In April 2014, the U.S. Court of Appeals for the D.C. Circuit issued a decision 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 power plant emissions of hazardous air pollutants, but did not vacate MATS. In 2016, the EPA issued a supplemental finding responding to the U.S. Supreme Court’s decision; the EPA concluded that, after considering costs, it remained appropriate and necessary to regulate hazardous air pollutants from power plants. On May 22, 2020, however, the EPA reversed course, publishing a final rule revoking the "appropriate and necessary" finding underpinning MATS. A coal mining company filed a lawsuit in the U.S. D.C. Circuit court seeking vacatur of MATS based on EPA’s May 22, 2020 ruling. On June 22, 2020, Exelon and two other entities filed a motion to intervene in that lawsuit to defend MATS, and on July 21, 2020, they separately filed a lawsuit in the D.C. Circuit court challenging the EPA’s May 22, 2020 rescission of the appropriate and necessary finding underpinning MATS.
The Clean Power Plan and Affordable Clean Energy Rule. The EPA’s 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide emissions from existing fossil-fired power plants under Clean Air Act Section 111(d). The CPP’s carbon pollution limits could be met through changes to the electric generation system, including shifting generation from higher-emitting units to lower- or zero-emitting units, as well as the development of new or expanded zero-emissions generation. In July 2019, the EPA published its final the Affordable Clean Energy rule, which repealed the CPP and replaced it with less stringent emissions guidelines for existing fossil-fired power plants based on heat rate improvement measures that could be achieved within the fence line of individual plants. Exelon, together with a coalition of other electric utilities, filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit on September 6, 2019, challenging the Affordable Clean Energy rule as unlawful. This lawsuit has been consolidated with separate challenges to the Affordable Clean Energy rule filed by various states, non-governmental organizations, and business coalitions.
Employees
In June 2020, Generation, ComEd, and DPL ratified or extended CBAs as follows:
•
Generation ratified its CBA with SPFPA Local 238, which covers 122 security officers at Quad Cities.  The CBA expires in 2023.  
•
ComEd extended its CBA with IBEW Local 15 to 2022, which covers 80 employees in the System Services Group.  
•
DPL ratified its CBAs with IBEW Locals 1238 and 1307, which together cover 857 employees. Both CBAs expire in 2024.


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Critical Accounting Policies and Estimates
Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. At June 30, 2020, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2019. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the Registrants' 2019 Form 10-K for further information.
Results of Operations by Registrant

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Results of Operations — Generation
Generation’s Results of Operations includes discussion of RNF, which is a financial measure not defined under GAAP and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. The CODMs for Exelon and Generation evaluate the performance of Generation's electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measure because it provides information that can be used to evaluate its operational performance.
 
Three Months Ended
June 30,
 
Favorable
(Unfavorable)
Variance
 
Six Months Ended
June 30,
 

(Unfavorable)
Favorable
Variance
 
2020
 
2019
 
 
2020
 
2019
 
Operating revenues
$
3,880

 
$
4,210

 
$
(330
)
 
$
8,613

 
$
9,506

 
$
(893
)
Purchased power and fuel expense
1,942

 
2,292

 
350

 
4,646

 
5,497

 
851

Revenues net of purchased power and fuel expense
1,938

 
1,918

 
20

 
3,967

 
4,009

 
(42
)
Other operating expenses
 
 
 
 
 
 
 
 
 
 
 
Operating and maintenance
1,189

 
1,266

 
77

 
2,451

 
2,484

 
33

Depreciation and amortization
300

 
409

 
109

 
604

 
814

 
210

Taxes other than income taxes
116

 
129

 
13

 
246

 
264

 
18

Total other operating expenses
1,605

 
1,804

 
199

 
3,301

 
3,562

 
261

Gain on sales of assets and businesses
12

 
33

 
(21
)
 
12

 
33

 
(21
)
Operating income
345


147

 
198

 
678


480

 
198

Other income and (deductions)
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(87
)
 
(116
)
 
29

 
(197
)
 
(227
)
 
30

Other, net
602

 
171

 
431

 
(168
)
 
601

 
(769
)
Total other income and (deductions)
515

 
55

 
460

 
(365
)
 
374

 
(739
)
Income before income taxes
860

 
202

 
658

 
313

 
854

 
(541
)
Income taxes
329

 
78

 
(251
)
 
(59
)
 
301

 
360

Equity in losses of unconsolidated affiliates
(2
)
 
(6
)
 
4

 
(4
)
 
(13
)
 
9

Net income
529


118


411


368


540


(172
)
Net income (loss) attributable to noncontrolling interests
53

 
10

 
43

 
(153
)
 
68

 
(221
)
Net income attributable to membership interest
$
476

 
$
108

 
$
368

 
$
521

 
$
472

 
$
49

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income attributable to membership interest increased $368 million by primarily due to:
•
Higher net unrealized and realized gains on NDT funds;
•
Higher mark-to-market gains; and
•
Lower operating and maintenance expense primarily due to lower contracting costs.
The increases were partially offset by:
•
Lower capacity revenue;

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•
Reduction in load due to COVID-19;
•
COVID-19 direct costs; and
•
Higher credit loss expense that includes the impacts of COVID-19.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income attributable to membership interest increased $49 million by primarily due to:
•
Higher mark-to-market gains;
•
Lower operating and maintenance expense primarily due to previous cost management programs and lower contracting costs;
•
The approval of the New Jersey ZEC program in the second quarter of 2019; and
•
An income tax settlement.
The increases were partially offset by:
•
Higher net unrealized and realized losses on NDT funds;
•
Lower capacity revenue;
•
Reduction in load due to COVID-19;
•
Higher nuclear outage days;
•
COVID-19 direct costs; and
•
Higher credit loss expense that includes the impacts of COVID-19.
Revenues Net of Purchased Power and Fuel Expense. The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned with these same geographic regions. Generation's five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. See Note 4 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.
The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall operating revenues or results of operations. Further, the following activities are not allocated to a region and are reported in Other: accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.
Generation evaluates the operating performance of electric business activities using the measure of RNF. Operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.

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For the three and six months ended June 30, 2020 compared to 2019, RNF by region were as follows. See Note 4 - Segment Information of the Combined Notes to the Consolidated Financial Statements for additional information on Purchase power and fuel expense for Generation’s reportable segments.
 
Three Months Ended
June 30,
 
Variance
 
% Change
 
Six Months Ended
June 30,
 
Variance
 
% Change
 
2020
 
2019
 
 
2020
 
2019
 
Mid-Atlantic(a)
$
525

 
$
652

 
$
(127
)
 
(19.5
)%
 
$
1,092

 
$
1,334

 
$
(242
)
 
(18.1
)%
Midwest(b)
703

 
730

 
(27
)
 
(3.7
)%
 
1,427

 
1,500

 
(73
)
 
(4.9
)%
New York
246

 
253

 
(7
)
 
(2.8
)%
 
440

 
519

 
(79
)
 
(15.2
)%
ERCOT
97

 
79

 
18

 
22.8
 %
 
177

 
154

 
23

 
14.9
 %
Other Power Regions
157

 
134

 
23

 
17.2
 %
 
312

 
292

 
20

 
6.8
 %
Total electric revenues net of purchased power and fuel expense
1,728

 
1,848

 
(120
)
 
(6.5
)%
 
3,448

 
3,799

 
(351
)
 
(9.2
)%
Mark-to-market gains (losses)
85

 
(74
)
 
159

 
214.9
 %
 
218

 
(102
)
 
320

 
313.7
 %
Other
125

 
144

 
(19
)
 
(13.2
)%
 
301

 
312

 
(11
)
 
(3.5
)%
Total revenue net of purchased power and fuel expense
$
1,938

 
$
1,918

 
$
20

 
1.0
 %
 
$
3,967

 
$
4,009

 
$
(42
)
 
(1.0
)%
_________
(a)
Includes results of transactions with PECO, BGE, Pepco, DPL and ACE.
(b)
Includes results of transactions with ComEd.




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Generation’s supply sources by region are summarized below:
 
Three Months Ended
June 30,
 
Variance
 
% Change
 
Six Months Ended
June 30,
 
Variance
 
% Change
Supply Source (GWhs)
2020
 
2019
 
 
2020
 
2019
 
Nuclear Generation(a)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mid-Atlantic
13,167

 
14,075

 
(908
)
 
(6.5
)%
 
25,951

 
29,155

 
(3,204
)
 
(11.0
)%
Midwest
23,860

 
23,996

 
(136
)
 
(0.6
)%
 
47,458

 
47,729

 
(271
)
 
(0.6
)%
New York
6,389

 
6,677

 
(288
)
 
(4.3
)%
 
12,562

 
13,579

 
(1,017
)
 
(7.5
)%
Total Nuclear Generation
43,416

 
44,748

 
(1,332
)
 
(3.0
)%
 
85,971


90,463

 
(4,492
)
 
(5.0
)%
Fossil and Renewables
 
 
 
 
 
 
 
 
 
 
 
 

 

Mid-Atlantic
707

 
915

 
(208
)
 
(22.7
)%
 
1,560

 
1,865

 
(305
)
 
(16.4
)%
Midwest
268

 
328

 
(60
)
 
(18.3
)%
 
656

 
719

 
(63
)
 
(8.8
)%
New York
1

 
1

 
—

 
—
 %
 
2

 
2

 
—

 
—
 %
ERCOT
3,251

 
3,066

 
185

 
6.0
 %
 
6,263

 
6,144

 
119

 
1.9
 %
Other Power Regions
2,603

 
2,514

 
89

 
3.5
 %
 
6,110

 
5,654

 
456

 
8.1
 %
Total Fossil and Renewables
6,830

 
6,824

 
6

 
0.1
 %
 
14,591


14,384

 
207

 
1.4
 %
Purchased Power
 
 
 
 
 
 
 
 
 
 
 
 

 

Mid-Atlantic
3,730

 
2,557

 
1,173

 
45.9
 %
 
9,672

 
5,123

 
4,549

 
88.8
 %
Midwest
236

 
250

 
(14
)
 
(5.6
)%
 
524

 
538

 
(14
)
 
(2.6
)%
ERCOT
1,255

 
1,213

 
42

 
3.5
 %
 
2,246

 
2,255

 
(9
)
 
(0.4
)%
Other Power Regions
11,303

 
11,116

 
187

 
1.7
 %
 
23,469

 
23,684

 
(215
)
 
(0.9
)%
Total Purchased Power
16,524

 
15,136

 
1,388

 
9.2
 %
 
35,911


31,600

 
4,311

 
13.6
 %
Total Supply/Sales by Region(c)
 
 
 
 
 
 
 
 
 
 
 
 

 

Mid-Atlantic(b)
17,604

 
17,547

 
57

 
0.3
 %
 
37,183

 
36,143

 
1,040

 
2.9
 %
Midwest(b)
24,364

 
24,574

 
(210
)
 
(0.9
)%
 
48,638

 
48,986

 
(348
)
 
(0.7
)%
New York
6,390

 
6,678

 
(288
)
 
(4.3
)%
 
12,564

 
13,581

 
(1,017
)
 
(7.5
)%
ERCOT
4,506

 
4,279

 
227

 
5.3
 %
 
8,509

 
8,399

 
110

 
1.3
 %
Other Power Regions
13,906

 
13,630

 
276

 
2.0
 %
 
29,579

 
29,338

 
241

 
0.8
 %
Total Supply/Sales by Region
66,770

 
66,708

 
62

 
0.1
 %
 
136,473


136,447

 
26

 
—
 %
_________
(a)
Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG).
(b)
Includes affiliate sales to PECO, BGE, Pepco, DPL and ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.
(c)
Reflects a decrease in load due to COVID-19.

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For the three and six months ended June 30, 2020 compared to 2019, changes in RNF by region were as follows:
 
Increase/ (Decrease)
Three Months Ended
June 30, 2020
Increase/ (Decrease)
Six Months Ended June 30, 2020
Mid-Atlantic
$
(127
)
• decreased capacity revenue
• decreased revenue due to permanent cease of generation operations at Three Mile Island in the third quarter of 2019
• decreased load due to COVID-19
• lower realized energy prices, partially offset by
• increased ZEC revenues due to decreased nuclear outage days at Salem
$
(242
)
• decreased capacity revenue
• decreased revenue due to permanent cease of generation operations at Three Mile Island in the third quarter of 2019
• decreased load due to COVID-19
• lower realized energy prices, partially offset by
• increased ZEC revenues due to the approval of the NJ ZEC program in the second quarter of 2019


Midwest
(27
)
• decreased capacity revenue
• decreased load due to COVID-19
• lower realized energy prices


(73
)
• decreased capacity revenue
• decreased load due to COVID-19
• lower realized energy prices
New York
(7
)
• decreased load due to COVID-19
• lower realized energy prices, partially offset by
• increased capacity revenues
(79
)
• decreased load due to COVID-19
• lower realized energy prices
• increased nuclear outage days



ERCOT
18

• higher portfolio optimization, partially offset by
• decreased load due to COVID-19

23

• higher portfolio optimization partially offset by
• decreased load due to COVID-19
Other Power Regions
23

• higher portfolio optimization, partially offset by
• decreased capacity revenue
• decreased load due to COVID-19

20

• higher portfolio optimization, partially offset by
• decreased capacity revenue
• decreased load due to COVID-19

Mark-to-market(a)
159

• gains on economic hedging activities of $85 million in 2020 compared to losses of $74 million in 2019
320

• gains on economic hedging activities of $218 million in 2020 compared to losses of $102 million in 2019
Other
(19
)
• decreased revenue related to the energy efficiency business
(11
)
• decreased revenue related to the energy efficiency business

Total
$
20

 
$
(42
)
 
_________
(a)
See Note 11 — Derivative Financial Instruments for additional information on mark-to-market gains (losses).

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Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for the Generation-operated plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2020
 
2019
 
2020
 
2019
Nuclear fleet capacity factor
95.4
%
 
95.1
%
 
94.7
%
 
96.1
%
Refueling outage days
92

 
56

 
186

 
130

Non-refueling outage days
—

 
28

 
11

 
28

The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
Litigation Settlements
$
26

 
$
26

COVID-19 Direct Costs
23

 
23

Nuclear refueling outage costs, including the co-owned Salem plants
12

 
54

Credit loss expense(a)
12

 
17

Asset Impairments
9

 
5

Pension and non-pension postretirement benefits expense
(4
)
 
(9
)
Accretion expense
(5
)
 
(15
)
Other
(9
)
 
(4
)
Travel and Entertainment
(11
)
 
(12
)
Plant retirements and divestitures
(13
)
 
69

Corporate allocations
(16
)
 
(27
)
Labor, other benefits, contracting and materials(b)
(101
)
 
(160
)
Increase in operating and maintenance expense
$
(77
)
 
$
(33
)
_________ 
(a)
Increased credit loss expense including impacts from COVID-19.
(b)
Primarily reflects decreased costs related to the permanent cease of generation operations at TMI and lower labor costs resulting from previous cost management programs.
Depreciation and amortization expense for the three and six months ended June 30, 2020 compared to the same period in 2019 decreased primarily due to the permanent cease of generation operations at Three Mile Island in the third quarter of 2019.
Taxes other than income taxes for the three and six months ended June 30, 2020 compared to the same period in 2019 decreased primarily due to decreased sales and power usage.

Gain on sales of assets and businesses for the three and six months ended June 30, 2020 compared to the same period in 2019 decreased primarily due to Generation's gain on sale of certain wind assets in the second quarter of 2019.
Interest Expense for the three and six months ended June 30, 2020 compared to the same period in 2019 decreased primarily due to the maturity of long-term debt in the first and second quarter of 2020.

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Other, net for the three months ended June 30, 2020 compared to the same period in 2019 increased and for the six months ended June 30, 2020 compared to the same period in 2019 decreased due to activity associated with NDT funds as described in the table below:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
2020
 
2019
 
2020
 
2019
Net unrealized (losses) gains on NDT funds(a)
$
452


$
(98
)
 
$
(253
)
 
$
182

Net realized gains on sale of NDT funds(a)
3

 
193

 
58

 
222

Interest and dividend income on NDT funds(a)
19

 
36

 
46

 
61

Contractual elimination of income tax expense(b)
134

 
34

 
(43
)
 
120

Other
(6
)
 
6

 
24

 
16

Total other, net
$
602

 
$
171

 
$
(168
)
 
$
601

_________ 
(a)
Unrealized gains (losses), realized gains and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement units.
(b)
Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement units.
Effective income tax rates were 38.3% and 38.6% for the three months ended June 30, 2020 and 2019, respectively. Generation's effective income tax rates were (18.8)% and 35.2% for the six months ended June 30, 2020 and 2019, respectively. The change primarily reflects one-time tax settlements. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information
Net income attributable to noncontrolling interests for the three months ended June 30, 2020 compared to the same period in 2019 increased primarily due to higher net gains on NDT fund investments for CENG and for the six months ended June 30, 2020 compared to the same period in 2019 decreased primarily due to unrealized losses on NDT fund investments for CENG.

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Results of Operations — ComEd
 
Three Months Ended
June 30,
 
Favorable
(Unfavorable)
Variance
 
Six Months Ended
June 30,
 
Favorable
(Unfavorable)
Variance
 
2020
 
2019
 
 
2020
 
2019
 
Operating revenues
$
1,417

 
$
1,351

 
$
66

 
$
2,856

 
$
2,759

 
$
97

Operating expenses
 
 
 
 
 
 
 
 
 
 
 
Purchased power expense
464

 
407

 
(57
)
 
951

 
892

 
(59
)
Operating and maintenance
536

 
305

 
(231
)
 
853

 
626

 
(227
)
Depreciation and amortization
274

 
257

 
(17
)
 
547

 
508

 
(39
)
Taxes other than income taxes
71

 
71

 
—

 
146

 
148

 
2

Total operating expenses
1,345

 
1,040

 
(305
)
 
2,497

 
2,174

 
(323
)
Gain on sales of assets
—

 
—

 
—

 
—

 
3

 
(3
)
Operating income
72

 
311

 
(239
)
 
359

 
588

 
(229
)
Other income and (deductions)
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(98
)
 
(89
)
 
(9
)
 
(192
)
 
(178
)
 
(14
)
Other, net
11

 
10

 
1

 
22

 
19

 
3

Total other income and (deductions)
(87
)
 
(79
)
 
(8
)
 
(170
)
 
(159
)
 
(11
)
(Loss) income before income taxes
(15
)
 
232

 
(247
)
 
189

 
429

 
(240
)
Income taxes
46

 
46

 
—

 
82

 
85

 
3

Net (loss) income
$
(61
)
 
$
186

 
$
(247
)
 
$
107

 
$
344

 
$
(237
)
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income decreased $247 million as compared to the same period in 2019, primarily due to payments that ComEd will make under the Deferred Prosecution Agreement, an impairment charge resulting from acquisition of transmission assets, and distribution formula rate timing. See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income decreased $237 million as compared to the same period in 2019, primarily due to payments that ComEd will make under the Deferred Prosecution Agreement, an impairment charge resulting from acquisition of transmission assets, and lower allowed electric distribution ROE due to a decrease in treasury rates, partially offset by higher electric distribution formula rate earnings (reflecting the impacts of higher rate base). See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.
The changes in Operating revenues consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
Electric distribution
$
—

 
$
21

Transmission
(4
)
 
(12
)
Energy efficiency
6

 
19

 
2

 
28

Regulatory required programs
64

 
69

Total increase
$
66

 
$
97


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ComEd

Revenue Decoupling. The demand for electricity is affected by weather conditions and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer or number of customers as a result of a change to the electric distribution formula rate pursuant to FEJA.
Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue for the three months ended June 30, 2020 compared to the same period in 2019 remained relatively consistent. Electric distribution revenue increased during the six months ended June 30, 2020 as compared to the same period in 2019, primarily due to the impact of higher rate base and higher fully recoverable costs, offset by lower allowed ROE due to a decrease in treasury rates. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the three and six months ended June 30, 2020 as compared to the same period in 2019, primarily due to the impact of decreased peak load partially offset by higher fully recoverable costs. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the three and six months ended June 30, 2020 as compared to the same period in 2019, primarily due to the increased regulatory asset amortization. See Depreciation and amortization expense discussions below and Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, and costs related to electricity, ZEC and REC procurement. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to electricity, ZEC and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. ComEd recovers electricity, ZEC and REC procurement costs from customers without mark-up.
See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The increase of $57 million and $59 million for the three and six months ended June 30, 2020 compared to the same period in 2019, respectively, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

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ComEd

The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2020
 
Increase (Decrease)
 
(Decrease) Increase
Deferred Prosecution Agreement payments(a)
$
200

 
$
200

Storm-related costs
9

 
2

BSC costs
6

 
16

Pension and non-pension postretirement benefits expense
2

 
4

Labor, other benefits, contracting and materials
1

 
(9
)
Other(b)
10

 
13

 
228

 
226

Regulatory required programs(c)
3

 
1

Total increase
$
231

 
$
227

__________
(a)
See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
(b)
Primarily reflects impairment charge related to acquisition of transmission assets.
(c)
ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism. During the three and six months ended June 30, 2020, ComEd recorded a net increase in credit losses account due to the timing of regulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenues for the period presented.

The changes in Depreciation and amortization expense consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2020
 
Increase
 
Increase
Depreciation and amortization(a)
$
14

 
$
28

Regulatory asset amortization(b)
3

 
11

Total increase
$
17

 
$
39

_________
(a)
Reflects ongoing capital expenditures.
(b)
Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Effective income tax rate were (306.7)% and 19.8% for the three months ended June 30, 2020 and 2019, respectively, and 43.4% and 19.8% for the six months ended June 30, 2020 and 2019. See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PECO

Results of Operations — PECO
 
Three Months Ended
June 30,
 
Favorable
(Unfavorable)
Variance
 
Six Months Ended
June 30,
 
Favorable
(Unfavorable)
Variance
 
2020
 
2019
 
 
2020
 
2019
 
Operating revenues
$
681

 
$
655

 
$
26

 
$
1,493

 
$
1,554

 
$
(61
)
Operating expenses
 
 
 
 
 
 
 
 
 
 
 
Purchased power and fuel expense

216

 
191

 
(25
)
 
499

 
520

 
21

Operating and maintenance
275

 
199

 
(76
)
 
492

 
424

 
(68
)
Depreciation and amortization
88

 
83

 
(5
)
 
173

 
164

 
(9
)
Taxes other than income taxes
39

 
37

 
(2
)
 
78

 
79

 
1

Total operating expenses
618

 
510

 
(108
)
 
1,242

 
1,187

 
(55
)
Operating income
63

 
145

 
(82
)
 
251

 
367

 
(116
)
Other income and (deductions)
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(36
)
 
(33
)
 
(3
)
 
(71
)
 
(67
)
 
(4
)
Other, net
5

 
3

 
2

 
7

 
7

 
—

Total other income and (deductions)
(31
)
 
(30
)
 
(1
)
 
(64
)
 
(60
)
 
(4
)
Income before income taxes
32

 
115

 
(83
)
 
187

 
307

 
(120
)
Income taxes
(7
)
 
13

 
20

 
9

 
37

 
28

Net income
$
39

 
$
102

 
$
(63
)
 
$
178

 
$
270

 
$
(92
)
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income decreased by $63 million primarily due to higher storm costs due to June 2020 storms and an increase in credit loss expense including the impacts of COVID-19, partially offset by favorable weather conditions.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income decreased by $92 million primarily due to unfavorable weather conditions, higher storm costs due to June 2020 storms, and an increase in credit loss expense including the impacts of COVID-19.
The changes in Operating revenues consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
 
Electric
 
Gas
 
Total
 
Electric
 
Gas
 
Total
Weather
$
3

 
$
8

 
$
11

 
$
(23
)
 
$
(13
)
 
$
(36
)
Volume
3

 
(3
)
 
—

 
(4
)
 
(6
)
 
(10
)
Pricing
(2
)
 
1

 
(1
)
 
6

 
5

 
11

Transmission
—

 
—

 
—

 
2

 
—

 
2

Other
(4
)
 
—

 
(4
)
 
(4
)
 
(1
)
 
(5
)
 
—

 
6

 
6

 
(23
)
 
(15
)
 
(38
)
Regulatory required programs
20

 
—

 
20

 
27

 
(50
)
 
(23
)
Total increase (decrease)
$
20

 
$
6

 
$
26

 
$
4

 
$
(65
)
 
$
(61
)
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended June 30, 2020 compared to the same period in 2019, Operating revenues related to weather increased by the impact of favorable weather conditions in PECO's service territory. During the six months ended

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PECO

June 30, 2020 compared to the same period in 2019, Operating revenues related to weather decreased by the impact of unfavorable weather conditions in PECO's service territory.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and six months ended June 30, 2020 compared to the same period in 2019 and normal weather consisted of the following:
Heating and Cooling Degree-Days
 
 
Normal
 
% Change
Three Months Ended June 30,
2020
 
2019
From 2019
 
2020 vs. Normal
Heating Degree-Days
568

 
270
 
432
 
110.4
 %
 
31.5
 %
Cooling Degree-Days
376

 
425
 
386
 
(11.5
)%
 
(2.6
)%
 
 
 
 
 
 
 
 
 
 
Six Months Ended June 30,
 
 
 
 
 
 
 
 
 
Heating Degree-Days
2,557

 
2,702
 
2,850
 
(5.4
)%
 
(10.3
)%
Cooling Degree-Days
376

 
427
 
387
 
(11.9
)%
 
(2.8
)%
Volume. Electric volume, exclusive of the effects of weather, for the three months ended June 30, 2020 compared to the same period in 2019, increased on a net basis due to an increase in usage for residential customers partially offset by a decrease for commercial and industrial customers due to COVID-19.  Residential volumes were further increased by customer growth.  Electric volume, exclusive of the effects of weather, for the six months ended June 30, 2020 compared to the same period in 2019, decreased on a net basis due to a decrease in usage for commercial and industrial customers partially offset by an increase in usage for residential customers due to COVID-19. Volumes further decreased as a result of the impact of energy efficiency initiatives across all customer classes partially offset by increases due to customer growth. Natural gas volume for the three and six months ended June 30, 2020, compared to the same period in 2019, decreased on a net basis due to a decrease in usage for the commercial and industrial natural gas classes partially offset by increased usage for the residential natural gas class due to COVID-19.
Electric Retail Deliveries to Customers (in GWhs)
Three Months Ended
June 30,
 
% Change
 
Weather -
Normal
% Change(b)
 
Six Months Ended June 30,
 
% Change
 
Weather -
Normal
% Change(b)
2020
 
2019
 
 
2020
 
2019
 
Residential
3,143
 
2,821
 
11.4
 %
 
8.4
 %
 
6,397
 
6,462
 
(1.0
)%
 
3.3
 %
Small commercial & industrial
1,571
 
1,823
 
(13.8
)%
 
(12.9
)%
 
3,476
 
3,889
 
(10.6
)%
 
(7.7
)%
Large commercial & industrial
3,181
 
3,769
 
(15.6
)%
 
(14.7
)%
 
6,602
 
7,340
 
(10.1
)%
 
(9.2
)%
Public authorities & electric railroads
112
 
182
 
(38.5
)%
 
(38.5
)%
 
263
 
377
 
(30.2
)%
 
(30.4
)%
Total electric retail deliveries(a)
8,007
 
8,595
 
(6.8
)%
 
(7.1
)%
 
16,738
 
18,068
 
(7.4
)%
 
(4.8
)%
 
As of June 30,
Number of Electric Customers
2020
 
2019
Residential
1,501,259
 
1,486,973
Small commercial & industrial
154,016
 
153,387
Large commercial & industrial
3,096
 
3,105
Public authorities & electric railroads
10,119
 
9,733
Total
1,668,490
 
1,653,198

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PECO

_________
(a)
Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)
Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Natural Gas Deliveries to Customers (in mmcf)
Three Months Ended
June 30,
 
% Change
 
Weather -
Normal
% Change(b)
 
Six Months Ended
June 30,
 
% Change
 
Weather -
Normal
% Change(b)
2020
 
2019
 
 
2020
 
2019
 
Residential
6,464
 
3,351
 
92.9
 %
 
9.3
 %
 
23,746
 
24,569
 
(3.3
)%
 
1.2
 %
Small commercial & industrial
2,054
 
4,040
 
(49.2
)%
 
(46.0
)%
 
10,863
 
14,684
 
(26.0
)%
 
(10.8
)%
Large commercial & industrial
3
 
17
 
(82.4
)%
 
(30.0
)%
 
12
 
36
 
(66.7
)%
 
(18.0
)%
Transportation
5,148
 
5,719
 
(10.0
)%
 
(16.0
)%
 
12,283
 
13,692
 
(10.3
)%
 
(8.0
)%
Total natural gas retail deliveries(a)
13,669
 
13,127
 
4.1
 %
 
(13.7
)%
 
46,904
 
52,981
 
(11.5
)%
 
(4.3
)%
 
As of June 30,
Number of Natural Gas Customers
2020
 
2019
Residential
489,201
 
483,657
Small commercial & industrial
44,189
 
43,953
Large commercial & industrial
6
 
2
Transportation
719
 
737
Total
534,115
 
528,349
_________
(a)
Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)
Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three months ended June 30, 2020 compared to the same period in 2019 remained relatively consistent. Pricing for the six months ended June 30, 2020 compared to the same period in 2019 increased primarily due to higher overall effective rates due to decreased usage across all major customer classes. Additionally, the increase represents revenue from higher natural gas distribution rates.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the three and six months ended June 30, 2020 compared to the same period in 2019 remained relatively consistent.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries but impact Operating revenues related to supplied electricity and natural gas. Drivers of Operating revenues related to commodity and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. PECO recovers electricity, natural gas and REC procurement costs from customers without mark-up.
Other revenue primarily includes revenue related to late payment charges. Other revenues decreased for the three and six months ended June 30, 2020, compared to the same period in 2019, as PECO temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored service to customers upon request who were disconnected in the last twelve months.
See Note 4— Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

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PECO

The increase of $25 million and decrease of $21 million for the three and six months ended June 30, 2020 compared to the same period in 2019, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2020
 
Increase (Decrease)
 
(Decrease) Increase
Storm-related costs(a)
$
61

 
$
53

Credit loss expense(b)
18

 
19

Labor, other benefits, contracting and materials
1

 
(5
)
Pension and non-pension postretirement benefits expense
(1
)
 
(1
)
Other
(3
)
 
2

Total increase
$
76

 
$
68

__________
(a) Reflects increased storm costs due to the June 2020 storms.
(b) Increased credit loss expense including impacts from COVID-19.

The changes in Depreciation and amortization expense consisted of the following:
 
Three Months Ended June 30, 2020
 
Six Months Ended
June 30, 2020
 
Increase
 
Increase (Decrease)
Depreciation and amortization(a)
$
5

 
$
10

Regulatory asset amortization
—

 
(1
)
Total increase
$
5

 
$
9

__________
(a)
Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective Income Tax Rates were (21.9)% and 11.3% for the three months ended June 30, 2020 and 2019, respectively, and 4.8% and 12.1% for the six months ended June 30, 2020 and 2019. See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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BGE


Results of Operations — BGE
 
Three Months Ended
June 30,
 
(Unfavorable)
Favorable
Variance
 
Six Months Ended
June 30,
 
(Unfavorable)
Favorable
Variance
 
2020
 
2019
 
 
2020
 
2019
 
Operating revenues
$
616

 
$
649

 
$
(33
)
 
$
1,554

 
$
1,625

 
$
(71
)
Operating expenses


 


 


 
 
 
 
 
 
Purchased power and fuel expense
194

 
208

 
14

 
483

 
570

 
87

Operating and maintenance
187

 
182

 
(5
)
 
376

 
372

 
(4
)
Depreciation and amortization
129

 
117

 
(12
)
 
272

 
252

 
(20
)
Taxes other than income taxes
63

 
62

 
(1
)
 
132

 
131

 
(1
)
Total operating expenses
573

 
569

 
(4
)
 
1,263

 
1,325

 
62

Operating income
43

 
80

 
(37
)
 
291

 
300

 
(9
)
Other income and (deductions)
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(32
)
 
(29
)
 
(3
)
 
(64
)
 
(58
)
 
(6
)
Other, net
6

 
5

 
1

 
10

 
11

 
(1
)
Total other income and (deductions)
(26
)
 
(24
)
 
(2
)
 
(54
)
 
(47
)
 
(7
)
Income before income taxes
17

 
56

 
(39
)
 
237

 
253

 
(16
)
Income taxes
(22
)
 
11

 
33

 
18

 
47

 
29

Net income
$
39

 
$
45

 
$
(6
)
 
$
219

 
$
206

 
$
13

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income remained relatively consistent.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income increased by $13 million primarily due to higher natural gas and electric distribution rates that became effective December 2019.
The changes in Operating revenues consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
 
Electric
 
Gas
 
Total
 
Electric
 
Gas
 
Total
Distribution
$
1

 
$
6

 
$
7

 
$
10

 
$
35

 
$
45

Transmission
(17
)
 
—

 
(17
)
 
(11
)
 
—

 
(11
)
Other
(5
)
 
(3
)
 
(8
)
 
(2
)
 
(4
)
 
(6
)
 
(21
)
 
3

 
(18
)
 
(3
)
 
31

 
28

Regulatory required programs
(14
)
 
(1
)
 
(15
)
 
(77
)
 
(22
)
 
(99
)
Total (decrease) increase
$
(35
)
 
$
2

 
$
(33
)
 
$
(80
)
 
$
9

 
$
(71
)
Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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BGE


 
As of June 30,
Number of Electric Customers
2020
 
2019
Residential
1,185,718

 
1,171,815

Small commercial & industrial
114,118

 
113,982

Large commercial & industrial
12,416

 
12,275

Public authorities & electric railroads
264

 
264

Total
1,312,516

 
1,298,336

 
As of June 30,
Number of Natural Gas Customers
2020
 
2019
Residential
643,745

 
634,939

Small commercial & industrial
38,255

 
38,164

Large commercial & industrial
6,079

 
5,991

Total
688,079

 
679,094

Distribution Revenue increased for the three and six months ended June 30, 2020, compared to the same period in 2019, primarily due to the impact of higher natural gas and electric distribution rates that became effective in December 2019. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the three and six months ended June 30, 2020, compared to the same period in 2019, primarily due to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes revenue related to mutual assistance, administrative charges, off-system sales, and late payment charges. Other revenues decreased for the three and six months ended June 30, 2020, compared to the same period in 2019, as BGE temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored service to customers upon request who were disconnected in the last twelve months.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries but impact Operating revenues related to supplied electricity and natural gas. Drivers of Operating revenues related to commodity procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. BGE recovers electricity, natural gas and procurement costs from customers with a slight mark-up.
See Note 4 — Segment Information of the Combined Notes to the Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The decrease of $14 million and decrease of $87 million for the three and six months ended June 30, 2020 compared to the same period in 2019, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.


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BGE


The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
Credit loss expense
$
7

 
$
6

BSC costs

1

 
4

Labor, other benefits, contracting and materials
1

 
3

Storm-related costs

—

 
(5
)
Pension and non-pension postretirement benefits expense
(1
)
 
(1
)
Other
(2
)
 
(2
)
 
6

 
5

Regulatory required programs
(1
)
 
(1
)
Total increase
$
5

 
$
4

 
The changes in Depreciation and amortization expense consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2020
 
Increase
 
Increase (Decrease)
Depreciation and amortization(a)
$
9

 
$
21

Regulatory required programs
3

 
(1
)
Total increase
$
12

 
$
20

_________
(a)
Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective income tax rates were (129.4)% and 19.6% for the three months ended June 30, 2020 and 2019, respectively, and 7.6% and 18.6% for the six months ended June 30, 2020 and 2019. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters and Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PHI

Results of Operations — PHI
PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. See the Results of Operations for Pepco, DPL and ACE for additional information.
 
Three Months Ended
June 30,
 
(Unfavorable)Favorable Variance
 
Six Months Ended
June 30,
 
(Unfavorable)Favorable Variance
 
2020
 
2019
 
 
2020
 
2019
 
PHI
$
94

 
$
106

 
$
(12
)
 
$
202

 
$
223

 
$
(21
)
Pepco
57

 
64

 
(7
)
 
109

 
119

 
(10
)
DPL
19

 
30

 
(11
)
 
64

 
83

 
(19
)
ACE
18

 
14

 
4

 
31

 
24

 
7

Other(a)
—

 
(2
)
 
2

 
(2
)
 
(3
)
 
1

_________
(a)
Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities and other financing and investing activities.
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net Income decreased by $12 million primarily due to an increase in credit loss expense including the impacts of COVID-19 and an increase in various expenses, partially offset by higher electric distribution rates primarily at ACE.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net Income decreased by $21 million primarily due to an increase in credit loss expense including the impacts of COVID-19, unfavorable weather conditions in ACE's service territory and an increase in various expenses, partially offset by higher electric distribution rates primarily at ACE.


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Table of Contents
Pepco


Results of Operations — Pepco
 
Three Months Ended June 30,
 
(Unfavorable) Favorable Variance
 
Six Months Ended June 30,
 
(Unfavorable) Favorable Variance
2020
 
2019
 
 
2020
 
2019
 
Operating revenues
$
494

 
$
531

 
$
(37
)
 
$
1,039

 
$
1,106

 
$
(67
)
Operating expenses
 
 
 
 
 
 
 
 
 
 
 
Purchased power expense
138

 
144

 
6

 
303

 
331

 
28

Operating and maintenance
119

 
111

 
(8
)
 
231

 
230

 
(1
)
Depreciation and amortization
92

 
93

 
1

 
186

 
186

 
—

Taxes other than income taxes
87

 
90

 
3

 
179

 
182

 
3

Total operating expenses
436

 
438

 
2

 
899

 
929

 
30

Operating income
58

 
93

 
(35
)
 
140

 
177

 
(37
)
Other income and (deductions)
 
 
 
 

 
 
 
 
 
 
Interest expense, net
(34
)
 
(34
)
 
—

 
(68
)
 
(68
)
 
—

Other, net
9

 
7

 
2

 
18

 
14

 
4

Total other income and (deductions)
(25
)
 
(27
)
 
2

 
(50
)
 
(54
)
 
4

Income before income taxes
33

 
66

 
(33
)
 
90

 
123

 
(33
)
Income taxes
(24
)
 
2

 
26

 
(19
)
 
4

 
23

Net income
$
57

 
$
64

 
$
(7
)
 
$
109

 
$
119

 
$
(10
)
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income decreased by $7 million primarily due to an increase in credit loss expense including the impacts of COVID-19.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income decreased by $10 million primarily due to an increase in credit loss expense including the impacts of COVID-19.
The changes in Operating revenues consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
Volume
$
2

 
$
4

Distribution
2

 
3

Transmission
(26
)
 
(28
)
Other
(1
)
 
(2
)
 
(23
)
 
(23
)
Regulatory required programs
(14
)
 
(44
)
Total decrease
$
(37
)
 
$
(67
)
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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Table of Contents
Pepco


Volume, exclusive of the effects of weather, remained relatively consistent for three and six months ended June 30, 2020 compared to the same period in 2019.
 
As of June 30,
Number of Electric Customers
2020
 
2019
Residential
825,000

 
811,985

Small commercial & industrial
53,809

 
54,194

Large commercial & industrial
22,467

 
22,155

Public authorities & electric railroads
168

 
155

Total
901,444

 
888,489

Distribution Revenue increased for the three and six months ended June 30, 2020 compared to the same period in 2019, due to higher electric distribution rates in Maryland that became effective in August 2019.
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 decreased for the three and six months ended June 30, 2020 compared to the same period in 2019, primarily due to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of other taxes. Other revenue decreased for the three and six months ended June 30, 2020, compared to the same period in 2019, as Pepco temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored services to customers upon request who were disconnected in the last twelve months.
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 procurement and 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 Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to commodity and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.
See Note 4 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The decrease of $6 million and $28 million for the three and six months ended June 30, 2020 compared to the same period 2019, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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Table of Contents
Pepco


The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
Labor, other benefits, contracting and materials

$
5

 
$
12

Credit loss expense
8

 
7

Storm-related costs
1

 
(1
)
Pension and non-pension postretirement benefits expense
(1
)
 
(3
)
BSC and PHISCO costs
—

 
(3
)
Expiration of lease arrangement
(4
)
 
(8
)
Other
(3
)
 
(4
)
 
6

 
—

Regulatory required programs
2

 
1

Total increase
$
8

 
$
1

The changes in Depreciation and amortization expense consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
Depreciation and amortization(a)
$
4

 
$
9

Regulatory required programs
(5
)
 
(9
)
Total decrease
$
(1
)
 
$
—

_________
(a)
Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were (72.7)% and 3.0% for the three months ended June 30, 2020 and 2019, respectively, and (21.1)% and 3.3% for the six months ended June 30, 2020 and 2019, respectively. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters and Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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Table of Contents
DPL


Results of Operations — DPL
 
Three Months Ended June 30,
 
(Unfavorable)Favorable Variance
 
Six Months Ended June 30,
 
(Unfavorable)Favorable Variance
2020
 
2019
 
 
2020
 
2019
 
Operating revenues
$
267

 
$
287

 
$
(20
)
 
$
617

 
$
667

 
$
(50
)
Operating expenses


 


 


 


 


 


Purchased power and fuel expense

107

 
107

 
—

 
249

 
271

 
22

Operating and maintenance
92

 
77

 
(15
)
 
172

 
160

 
(12
)
Depreciation and amortization
47

 
45

 
(2
)
 
94

 
91

 
(3
)
Taxes other than income taxes
17

 
14

 
(3
)
 
32

 
28

 
(4
)
Total operating expenses
263

 
243

 
(20
)
 
547

 
550

 
3

Operating income
4

 
44

 
(40
)
 
70

 
117

 
(47
)
Other income and (deductions)


 


 


 


 


 


Interest expense, net
(15
)
 
(15
)
 
—

 
(31
)
 
(30
)
 
(1
)
Other, net
2

 
5

 
(3
)
 
5

 
7

 
(2
)
Total other income and (deductions)
(13
)
 
(10
)
 
(3
)
 
(26
)
 
(23
)
 
(3
)
(Loss) income before income taxes
(9
)

34

 
(43
)
 
44


94

 
(50
)
Income taxes
(28
)
 
4

 
32

 
(20
)
 
11

 
31

Net income
$
19

 
$
30

 
$
(11
)
 
$
64

 
$
83

 
$
(19
)
Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income decreased by $11 million primarily due to an increase in credit loss expense including the impacts of COVID-19 and an increase in various expenses, partially offset by favorable weather conditions in DPL's Delaware service territory.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income decreased by $19 million primarily due to an increase in credit loss expense including the impacts of COVID-19 and an increase in various expenses.
The changes in Operating revenues consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
 
Electric
 
Gas
 
Total
 
Electric
 
Gas
 
Total
Weather
$
1

 
$
6

 
$
7

 
$
(5
)
 
$
—

 
$
(5
)
Volume
—

 
(3
)
 
(3
)
 
1

 
(3
)
 
(2
)
Distribution
—

 
—

 
—

 
2

 
3

 
5

Transmission
(25
)
 
—

 
(25
)
 
(22
)
 
—

 
(22
)
Other
(1
)
 
—

 
(1
)
 
(2
)
 
(1
)
 
(3
)
 
(25
)
 
3

 
(22
)
 
(26
)
 
(1
)
 
(27
)
Regulatory required programs
(1
)
 
3

 
2

 
(22
)
 
(1
)
 
(23
)
Total (decrease) increase
$
(26
)
 
$
6

 
$
(20
)
 
$
(48
)
 
$
(2
)
 
$
(50
)
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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Table of Contents
DPL


Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended June 30, 2020 compared to the same period in 2019, Operating revenues related to weather increased due to the impact of favorable weather conditions in DPL's Delaware service territory. During the six months ended June 30, 2020 compared to the same period in 2019, Operating revenues related to weather decreased due to the impact of unfavorable weather conditions in DPL's Delaware service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the three and six months ended June 30, 2020 compared to same period in 2019 and normal weather consisted of the following:
Delaware Electric Service Territory
 
 
 
 
% Change
Three Months Ended June 30,
2020
 
2019
 
Normal
 
2020 vs. 2019
 
2020 vs. Normal
Heating Degree-Days
606

 
300

 
467

 
102.0
 %
 
29.8
 %
Cooling Degree-Days
299

 
386

 
334

 
(22.5
)%
 
(10.5
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
% Change
Six Months Ended June 30,
2020
 
2019
 
Normal
 
2020 vs. 2019
 
2020 vs. Normal
Heating Degree-Days
2,609

 
2,822

 
2,980

 
(7.5
)%
 
(12.4
)%
Cooling Degree-Days
299

 
386

 
335

 
(22.5
)%
 
(10.7
)%
Delaware Natural Gas Service Territory
 
 
 
 
% Change
Three Months Ended June 30,
2020
 
2019
 
Normal
 
2020 vs. 2019
 
2020 vs. Normal
Heating Degree-Days
606

 
300

 
486

 
102.0
 %
 
24.7
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
% Change
Six Months Ended June 30,
2020
 
2019
 
Normal
 
2020 vs. 2019
 
2020 vs. Normal
Heating Degree-Days
2,609

 
2,822

 
2,984

 
(7.5
)%
 
(12.6
)%
Volume, exclusive of the effects of weather, remained relatively consistent for the three and six months ended June 30, 2020 compared to the same period in 2019.
Electric Retail Deliveries to Delaware Customers (in GWhs)
Three Months Ended
June 30,
 
% Change
 
Weather - Normal
% Change(b)
 
Six Months Ended
June 30,
 
% Change
 
Weather - Normal
% Change(b)
2020
 
2019
 
 
 
2020
 
2019
 
 
Residential
703

 
652

 
7.8
 %
 
4.6
 %
 
1,446

 
1,503

 
(3.8
)%
 
1.4
 %
Small commercial & industrial
274

 
306

 
(10.5
)%
 
(10.9
)%
 
570

 
626

 
(8.9
)%
 
(6.4
)%
Large commercial & industrial
810

 
866

 
(6.5
)%
 
(6.1
)%
 
1,633

 
1,676

 
(2.6
)%
 
(1.7
)%
Public authorities & electric railroads
9

 
9

 
—
 %
 
4.0
 %
 
17

 
17

 
—
 %
 
3.0
 %
Total electric retail deliveries(a)
1,796

 
1,833

 
(2.0
)%
 
(3.0
)%
 
3,666

 
3,822

 
(4.1
)%
 
(1.2
)%

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Table of Contents
DPL


 
As of June 30,
Number of Total Electric Customers (Maryland and Delaware)
2020
 
2019
Residential
470,788

 
465,423

Small commercial & industrial
61,958

 
61,552

Large commercial & industrial
1,402

 
1,398

Public authorities & electric railroads
612

 
619

Total
534,760

 
528,992

_________
(a)
Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)
Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Natural Gas Retail Deliveries to Delaware Customers (in mmcf)
Three Months Ended
June 30,
 
% Change
 
Weather - Normal
% Change(b)
 
Six Months Ended
June 30,
 
% Change
 
Weather - Normal
% Change(b)
2020
 
2019
 
 
 
2020
 
2019
 
 
Residential
1,168

 
741

 
57.6
 %
 
(11.8
)%
 
4,815

 
5,348

 
(10.0
)%
 
(2.8
)%
Small commercial & industrial
557

 
566

 
(1.6
)%
 
(35.0
)%
 
2,228

 
2,586

 
(13.8
)%
 
(7.4
)%
Large commercial & industrial
411

 
442

 
(7.0
)%
 
(7.0
)%
 
863

 
965

 
(10.6
)%
 
(10.6
)%
Transportation
1,472

 
1,475

 
(0.2
)%
 
(8.0
)%
 
3,580

 
3,693

 
(3.1
)%
 
(0.9
)%
Total natural gas deliveries(a)
3,608

 
3,224

 
11.9
 %
 
(14.1
)%
 
11,486

 
12,592

 
(8.8
)%
 
(3.8
)%
 
As of June 30,
Number of Delaware Natural Gas Customers
2020
 
2019
Residential
126,245

 
124,325

Small commercial & industrial
9,914

 
9,907

Large commercial & industrial
17

 
18

Transportation
159

 
158

Total
136,335

 
134,408

__________
(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 six months ended June 30, 2020 compared to the same period in 2019 primarily due to higher natural gas distribution rates due to the Gas Distribution System Improvement Charge (DSIC) fully implemented in the first quarter of 2020.
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 decreased for the three and six months ended June 30, 2020 compared to the same period in 2019 primarily due to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of other taxes. Other revenue decreased for the three and six months ended June 30, 2020 compared to the same period in 2019, as DPL temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored service to customers upon request who were disconnected in the last twelve months.

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Table of Contents
DPL


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 procurement and 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 Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to commodity and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up and natural gas costs from customers without mark-up.
See Note 4 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The decrease of $22 million for the six months ended June 30, 2020 compared to the same period in 2019 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
Labor, other benefits, contracting and materials
$
8

 
$
8

Credit loss expense
7

 
5

Storm-related costs
2

 
2

Pension and non-pension postretirement benefits expense
(1
)
 
(2
)
BSC and PHISCO costs
—

 
(2
)
Other
(5
)
 
(2
)
 
11

 
9

Regulatory required programs
4

 
3

Total increase
$
15

 
$
12

The changes in Depreciation and amortization expense consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended
June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
Depreciation and amortization(a)
$
3

 
$
5

Regulatory required programs
(1
)
 
(2
)
Total increase
$
2

 
$
3

_________
(a)
Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective income tax rates were 311.1% and 11.8% for the three months ended June 30, 2020 and 2019, respectively, and (45.5)% and 11.7% for the six months ended June 30, 2020 and 2019, respectively. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters and Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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Table of Contents
ACE


Results of Operations — ACE
 
Three Months Ended June 30,
 
(Unfavorable) Favorable Variance
 
Six Months Ended June 30,
 
(Unfavorable) Favorable Variance
 
2020
 
2019
 
 
2020
 
2019
 
Operating revenues
$
256

 
$
274

 
$
(18
)
 
$
532

 
$
547

 
$
(15
)
Operating expenses
 
 
 
 

 
 
 
 
 
 
Purchased power expense
130

 
131

 
1

 
259

 
270

 
11

Operating and maintenance
82

 
74

 
(8
)
 
160

 
155

 
(5
)
Depreciation and amortization
44

 
40

 
(4
)
 
86

 
71

 
(15
)
Taxes other than income taxes
2

 
1

 
(1
)
 
4

 
2

 
(2
)
Total operating expenses
258

 
246

 
(12
)
 
509

 
498

 
(11
)
Gain on sale of assets
—

 
—

 
—

 
2

 
—

 
2

Operating (loss) income
(2
)
 
28

 
(30
)
 
25

 
49

 
(24
)
Other income and (deductions)
 
 
 
 

 
 
 
 
 
 
Interest expense, net
(15
)
 
(15
)
 
—

 
(29
)
 
(28
)
 
(1
)
Other, net
2

 
1

 
1

 
3

 
4

 
(1
)
Total other income and (deductions)
(13
)

(14
)
 
1

 
(26
)
 
(24
)
 
(2
)
Income before income taxes
(15
)

14

 
(29
)
 
(1
)
 
25

 
(26
)
Income taxes
(33
)
 
—

 
33

 
(32
)
 
1

 
33

Net income
$
18

 
$
14

 
$
4

 
$
31

 
$
24

 
$
7

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income increased by $4 million primarily due to higher electric distribution rates that became effective in April 2020 partially offset by lower commercial and industrial usage.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income increased by $7 million primarily due to higher electric distribution rates that became effective in April 2019 and April 2020, partially offset by unfavorable weather conditions in ACE’s service territory, lower commercial and industrial usage and increased depreciation and amortization expense.
The changes in Operating revenues consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended June 30, 2020
 
(Decrease) Increase
 
(Decrease) Increase
Weather
$
(1
)
 
$
(5
)
Volume
(4
)
 
(6
)
Distribution
5

 
20

Transmission
(24
)
 
(18
)
Other
(1
)
 
(2
)
 
(25
)
 
(11
)
Regulatory required programs
7

 
(4
)
Total decrease
$
(18
)
 
$
(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. There was a decrease related to weather for the six months ended June 30, 2020 compared to same period in 2019 due to the impact of unfavorable weather conditions in ACE's service territory.

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Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the three and six months ended June 30, 2020 compared to same period in 2019 consisted of the following:
Heating and Cooling Degree-Days
 
 
Normal
 
% Change
Three Months Ended June 30,
2020
 
2019
 
 
2020 vs. 2019
 
2020 vs. Normal
Heating Degree-Days
613

 
380

 
541

 
61.3
 %
 
13.3
 %
Cooling Degree-Days
312

 
351

 
304

 
(11.1
)%
 
2.6
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
Normal
 
% Change
Six Months Ended June 30,
2020
 
2019
 
 
2020 vs. 2019
 
2020 vs. Normal
Heating Degree-Days
2,561

 
2,886

 
3,034

 
(11.3
)%
 
(15.6
)%
Cooling Degree-Days
312

 
351

 
305

 
(11.1
)%
 
2.3
 %
Volume, exclusive of the effects of weather, decreased for the three and six months ended June 30, 2020 compared to the same period in 2019, primarily due to lower commercial and industrial usage.
Electric Retail Deliveries to Customers (in GWhs)
Three Months Ended
June 30,
 
% Change
 
Weather - Normal % Change(b)
 
Six Months Ended June 30, 2020
 
% Change
 
Weather - Normal % Change(b)
2020
 
2019
 
 
 
2020
 
2019
 
 
Residential
850

 
804

 
5.7
 %
 
6.5
 %
 
1,660

 
1,713

 
(3.1
)%
 
1.3
 %
Small commercial & industrial
276

 
314

 
(12.1
)%
 
(12.8
)%
 
570

 
624

 
(8.7
)%
 
(6.4
)%
Large commercial & industrial
702

 
872

 
(19.5
)%
 
(19.3
)%
 
1,437

 
1,662

 
(13.5
)%
 
(12.7
)%
Public authorities & electric railroads
11

 
11

 
—
 %
 
2.8
 %
 
24

 
24

 
—
 %
 
(0.9
)%
Total electric retail deliveries(a)
1,839

 
2,001

 
(8.1
)%
 
(7.9
)%
 
3,691

 
4,023

 
(8.3
)%
 
(5.7
)%
 
As of June 30,
Number of Electric Customers
2020
 
2019
Residential
496,668

 
492,940

Small commercial & industrial
61,468

 
61,416

Large commercial & industrial
3,327

 
3,464

Public authorities & electric railroads
687

 
672

Total
562,150

 
558,492

_________
(a)
Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)
Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Distribution Revenue increased for the three and six months ended June 30, 2020 compared to the same period in 2019 primarily due to higher electric distribution rates that became effective in April 2019 and April 2020.
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 decreased for the three and six months ended June 30, 2020 compared to the same period in 2019, primarily due to settlement agreement for

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ACE


ongoing transmission-related income tax regulatory liabilities. See Note 2 — 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 procurement and 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 Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to commodity, REC and ZEC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power expense. ACE recovers electricity, REC and ZEC procurement costs from customers without mark-up.
See Note 4 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The decrease of $1 million and $11 million for three and six months ended June 30, 2020 compared to the same period in 2019 , respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
Labor, other benefits, contracting and materials
$
6

 
$
9

Storm-related costs
(1
)
 
(1
)
BSC and PHISCO costs
—

 
(1
)
Credit loss expense(a)
7

 
6

Other
(3
)
 
(8
)
 
9

 
5

Regulatory required programs
(1
)
 
—

Total increase
$
8

 
$
5

_________
(a)
ACE is allowed to recover from or refund to customers the difference between its annual credit loss 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 amortization expense consisted of the following:
 
Three Months Ended
June 30, 2020
 
Six Months Ended June 30, 2020
 
Increase (Decrease)
 
Increase (Decrease)
Depreciation and amortization(a)
$
3

 
$
12

Regulatory asset amortization
(2
)
 
(1
)
Regulatory required programs
3

 
4

Total increase
$
4

 
$
15

_________
(a)
Depreciation and amortization increased primarily due to ongoing capital expenditures.

Gain on sale of assets for the six months ended June 30, 2020 compared to the same period in 2019 increased due to the sale of land in February 2020.

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Effective income tax rates were 220.0% and 0.0% for the three months ended June 30, 2020 and 2019, respectively, 3,200.0% and 4.0% for the six months ended June 30, 2020 and 2019, respectively. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters and Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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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, the sale of certain receivables, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $10.7 billion. As a result of disruptions in the commercial paper markets due to COVID-19 in March of 2020, Generation borrowed $1.5 billion on its revolving credit facility to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020 using funds from short-term loans issued in March 2020, cash proceeds from the sale of certain customer accounts receivable, and borrowings from the Exelon intercompany money pool. See Note 5 - Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sale of customer accounts receivable. Exelon Corporate, Generation, and the Utility Registrants continued to issue commercial paper during the second quarter of 2020. See Executive Overview for additional information on COVID-19. The Registrants continue to utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
Despite disruptions in the financial markets due to COVID-19, the Registrants have been able to fund their liquidity needs to date. As of December 31, 2019, Exelon had approximately $4.0 billion of long-term debt that matures in 2020, excluding project financings and floating rate long-term debt. Of this, as of June 30, 2020, Exelon has redeemed or refinanced approximately $3.4 billion that is maturing in 2020. The remaining amount of $0.6 billion on Exelon’s and Generation’s Consolidated Balance Sheet matures in the fourth quarter of 2020. To date in 2020, the Registrants have been able to execute their expected debt issuances and have issued long-term debt of $5.1 billion, of which $4.0 billion was issued in the period of April to July of 2020. The Registrants accelerated the timing of a number of planned debt issuances resulting in the $4.0 billion issued in the period of April to July of 2020 and the Registrants have now completed their planned long-term debt issuances for the 2020 year.
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 7 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

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If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value. A shortfall could require that Generation address the shortfall by, among other things, obtaining a parental guarantee for Generation’s share of the funding assurance. However, the amount of any guarantees or other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. Upon issuance of any required financial guarantees, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, the NRC must approve an exemption in order for the plant’s owner(s) to utilize the NDT fund to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by the owner(s) without reimbursement from or access to the NDT funds. The ultimate costs for spent fuel management may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the DOE reimbursement agreements.
As of June 30, 2020, Exelon would not be required to post a parental guarantee for TMI Unit 1 under the SAFSTOR scenario which is the planned decommissioning option as described in the TMI Unit 1 PSDAR filed by Generation with the NRC on April 5, 2019. On October 16, 2019, the NRC granted Generation's exemption request to use the TMI Unit 1 NDT funds for spent fuel management costs. An additional exemption request would be required to allow the funds to be spent on site restoration costs, which are not expected to be incurred in the near term.
Project Financing (Exelon and Generation)
Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities. See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. Refer to Note 16 — Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on credit facilities.
Cash Flows from Operating Activities (All Registrants)
General
Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers and the sale of certain receivables.
The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions.
See Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2019 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 change in cash flows from operating activities for the six months ended June 30, 2020 and 2019 by Registrant:
(Decrease) increase in cash flows from operating activities
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Net income
$
(510
)
 
$
(172
)
 
$
(237
)
 
$
(92
)
 
$
13

 
$
(21
)
 
$
(10
)
 
$
(19
)
 
$
7

Adjustments to reconcile net income to cash:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-cash operating activities
305

 
44

 
315

 
17

 
4

 
(7
)
 
(29
)
 
18

 
10

Pension and non-pension postretirement benefit contributions
(203
)
 
(85
)
 
(76
)
 
9

 
(26
)
 
(20
)
 
—

 
1

 
(2
)
Income taxes
(265
)
 
(295
)
 
(133
)
 
26

 
55

 
(18
)
 
5

 
(23
)
 
(4
)
Changes in working capital and other noncurrent assets and liabilities
(46
)
 
(149
)
 
(24
)
 
115

 
1

 
(6
)
 
12

 
5

 
(14
)
Option premiums paid, net
(150
)
 
(150
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Collateral posted, net
651

 
660

 
(14
)
 
—

 
5

 
—

 
—

 
—

 
—

(Decrease) increase in cash flows from operating activities
$
(218
)
 
$
(147
)
 
$
(169
)
 
$
75

 
$
52

 
$
(72
)
 
$
(22
)
 
$
(18
)
 
$
(3
)
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 six months ended June 30, 2020 and 2019 were as follows:
•
See Note 17 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statement of Cash Flows for additional information on non-cash operating activity.
•
See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statement of Cash Flows for additional information on income taxes.
•
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 2020, Exelon and Generation derecognized approximately $1.2 billion of accounts receivable. See Note 5 — Accounts Receivable for additional information on the sales of customer accounts receivable.
Cash Flows from Investing Activities (All Registrants)
The following table provides a summary of the change in cash flows from investing activities for the six months ended June 30, 2020 and 2019 by Registrant:
Increase (decrease) in cash flows from investing activities
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Capital expenditures
$
(201
)
 
$
(40
)
 
$
(68
)
 
$
(65
)
 
$
(6
)
 
$
12

 
$
(26
)
 
$
(24
)
 
$
49

Proceeds from NDT fund sales, net
(125
)
 
(125
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Proceeds from sales of assets and businesses
(14
)
 
(14
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Changes in intercompany money pool
—

 
179

 
—

 
68

 
—

 
—

 
38

 
(55
)
 
—

Collection of DPP
1,102

 
1,102

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Other investing activities
(22
)
 
(2
)
 
(21
)
 
(1
)
 
(8
)
 
—

 
(4
)
 
(4
)
 
5

Increase (decrease) in cash flows from investing activities
$
740

 
$
1,100

 
$
(89
)
 
$
2

 
$
(14
)
 
$
12

 
$
8

 
$
(83
)
 
$
54


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Significant investing cash flow impacts for the Registrants for six months ended June 30, 2020 and 2019 were as follows:
•
Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer below for additional information on projected capital expenditure spending.
•
Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
Capital Expenditure Spending
As of June 30, 2020, the most recent estimates of capital expenditures for plant additions and improvements for 2020 are as follows:
(in millions)
Transmission
Distribution
Gas
Total
Exelon
N/A

N/A

N/A

$
8,075

Generation
N/A

N/A

N/A

1,500

ComEd
450

1,900

N/A

2,350

PECO
125

725

300

1,150

BGE
300

550

450

1,300

PHI
450

1,125

100

1,675

Pepco
150

700

N/A

850

DPL
125

225

100

450

ACE
175

200

N/A

375

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Cash Flows from Financing Activities (All Registrants)
The following table provides a summary of the change in cash flows from financing activities for the six months ended June 30, 2020 and 2019 by Registrant:
Increase (decrease) in cash flows from financing activities
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Changes in short-term borrowings, net
$
(596
)
 
$
280

 
$
(433
)
 
$
—

 
$
(270
)
 
$
(37
)
 
$
(28
)
 
$
(56
)
 
$
47

Long-term debt, net
2,356

 
(443
)
 
900

 
350

 
400

 
53

 
6

 
99

 
(52
)
Changes in intercompany money pool
—

 
100

 
—

 
(52
)
 
—

 
7

 
50

 
(38
)
 
5

Dividends paid on common stock
(42
)
 
—

 
5

 
10

 
(11
)
 
—

 
(29
)
 
4

 
(11
)
Distributions to member
—

 
(488
)
 
—

 
—

 
—

 
(52
)
 
—

 
—

 
—

Contributions from parent/member
—

 
—

 
125

 
86

 
26

 
76

 
8

 
106

 
(39
)
Other financing activities
(79
)
 
(9
)
 
(4
)
 
(2
)
 
(8
)
 
(4
)
 
(3
)
 
(1
)
 
—

Increase (decrease) in cash flows from financing activities
$
1,639

 
$
(560
)
 
$
593

 
$
392

 
$
137

 
$
43

 
$
4

 
$
114

 
$
(50
)
Significant financing cash flow impacts for the Registrants for the six months ended June 30, 2020 and 2019 were as follows:
•
Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to 12 — 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 12 — 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 dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2019 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
•
For the six months ended June 30, 2020, other financing activities primarily consists of debt issuance costs. See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.
Debt
See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.
During the six months ended June 30, 2020, the following long-term debt was retired and/or redeemed:
Company(a)
 
Type
 
Interest Rate
 
Maturity
 
Amount
Exelon
 
Notes
 
2.85
%
 
June 15, 2020
 
$
900

Exelon
 
Long-Term Software License Agreement
 
3.95
%
 
May 1, 2024
 
24

Generation
 
Senior Notes
 
2.95
%
 
January 15, 2020
 
1,000

Generation
 
Tax-Exempt Bonds
 
2.50% - 2.70%

 
December 1, 2025 - June 1, 2036
 
379

Generation
 
ExGen Renewables IV Nonrecourse Debt(b)
 
3mL +3%

 
November 30, 2024
 
22

Generation
 
Continental Wind Nonrecourse Debt(b)
 
6.00
%
 
February 28, 2033
 
18

Generation
 
Antelope Valley DOE Nonrecourse Debt(b)
 
2.29% - 3.56%

 
January 5, 2037
 
7

Generation
 
Energy Efficiency Project Financing
 
3.71
%
 
December 31, 2020
 
4

Generation
 
Renewable Power Generation Nonrecourse Debt(b)
 
4.11
%
 
March 31, 2035
 
3

Generation
 
SolGen Nonrecourse Debt
 
3.93
%
 
September 30, 2036
 
2

Generation
 
Energy Efficiency Project Financing
 
4.12
%
 
November 30, 2020
 
1

ACE
 
Tax-Exempt First Mortgage Bonds
 
4.88
%
 
June 1, 2029
 
23

ACE
 
Transition Bonds
 
5.55
%
 
October 20, 2023
 
9

_________
(a)
On July 1, Generation redeemed $550 million of 4.00% senior notes. On August 3, 2020, ComEd redeemed $500 million of first mortgage bonds, and DPL redeemed $78 million of tax-exempt bonds.
(b)
See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the six months ended June 30, 2020 and for the third quarter of 2020 were as follows:
Period
 
Declaration Date
 
Shareholder of Record Date
 
Dividend Payable Date
 
Cash per Share(a)
First Quarter 2020
 
January 28, 2020
 
February 20, 2020
 
March 10, 2020
 
$
0.3825

Second Quarter 2020
 
April 28, 2020
 
May 15, 2020
 
June 10, 2020
 
$
0.3825

Third Quarter 2020
 
July 28, 2020
 
August 14, 2020
 
September 10, 2020
 
$
0.3825

_________
(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.

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Credit Matters (All Registrants)
The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include $10.7 billion in aggregate total commitments of which $8.6 billion was available to support additional commercial paper as of June 30, 2020, 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 markets and had availability under their revolving credit facilities during the second quarter of 2020 to fund their short-term liquidity needs. 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 2019 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, 2020, it would have been required to provide incremental collateral of $1.3 billion to meet collateral obligations for derivatives, non-derivatives, normal purchases and normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within the $5 billion of available credit capacity of its revolver.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at June 30, 2020 and available credit facility capacity prior to any incremental collateral at June 30, 2020:
 
PJM Credit Policy Collateral
 
Other Incremental Collateral Required(a)
 
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd
$
4

 
$
—

 
$
998

PECO
—

 
24

 
600

BGE
11

 
26

 
600

Pepco
11

 
—

 
285

DPL
4

 
10

 
300

ACE
—

 
—

 
295

_________
(a)
Represents incremental collateral related to natural gas procurement contracts.
Exelon Credit Facilities
Exelon Corporate, ComEd and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ short-term borrowing activity. See Note 16 — Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on the Registrants’ credit facilities.
Security Ratings

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The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The Registrants’ credit ratings did not change for the six months ended June 30, 2020. On July 21, 2020, S&P lowered ComEd's long-term issuer credit rating from 'A-' to a 'BBB+'. S&P also affirmed the current 'A' rating on ComEd's senior secured debt and 'A-2' short-term rating, which influences long and short-term borrowing cost.
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, 2020, are presented in the following table:
Exelon Intercompany Money Pool
 
During the Three Months Ended June 30, 2020
 
As of June 30, 2020
Contributed (Borrowed)
 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
Exelon Corporate
 
$
1,364

 
$
—

 
$
372

Generation
 
—

 
(980
)
 
—

BSC
 
—

 
(504
)
 
(410
)
PHI Corporate
 
—

 
(22
)
 
(22
)
PCI
 
60

 
—

 
60

PHI Intercompany Money Pool
 
During the Three Months Ended June 30, 2020
 
As of June 30, 2020
Contributed (Borrowed)
 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
Pepco
 
$
126

 
$
(57
)
 
$
(50
)
DPL
 
62

 
(49
)
 
55

ACE
 
—

 
(77
)
 
(5
)
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 2022. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

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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, 2020
 
 
Short-term Financing Authority(a)
 
Remaining Long-term Financing Authority(a)
Commission
 
Expiration Date
 
Amount
Commission
 
Expiration Date
 
Amount
ComEd
 
FERC
 
December 31, 2021
 
$
2,500

 
ICC
 
February 1, 2023
 
$
893

PECO
 
FERC
 
December 31, 2021
 
1,500

 
PAPUC
 
December 31, 2021
 
1,225

BGE
 
FERC
 
December 31, 2021
 
700

 
MDPSC
 
N/A
 
1,100

Pepco
 
FERC
 
December 31, 2021
 
500

 
MDPSC / DCPSC
 
December 31, 2022
 
1,050

DPL
 
FERC
 
December 31, 2021
 
500

 
MDPSC / DPSC
 
December 31, 2022
 
375

ACE
 
NJBPU
 
December 31, 2021
 
350

 
NJBPU
 
December 31, 2020
 
77

_________
(a)
Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.

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 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 2019 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 in the Exelon 2019 Form 10-K 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 2019 Form 10-K. In addition, see discussion of off-balance sheet arrangement discussed below.
Sales of Customer Accounts Receivable
On April 8, 2020, Generation entered into an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain receivables, which expires on April 7, 2021 unless renewed by the mutual consent of the parties in accordance with its terms. The facility allows Generation to obtain financing at lower cost and diversify its sources of liquidity. See Note 5 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.


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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 2019 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 2020 through 2022.
As of June 30, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 98%-101% and 76%-79% for 2020 and 2021, respectively. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on June 30, 2020 market conditions and hedged position would be an increase in pre-tax net income of approximately $25 million for 2020 and a decrease of $189 million for 2021. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Fuel Procurement
Approximately 60% of Generation’s uranium concentrate requirements from 2020 through 2024 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s financial statements.
Utility Registrants
There have been no significant changes or additions to the Utility Registrants exposures to commodity price risk that were described in ITEM 1A. RISK FACTORS of Exelon’s 2019 Annual Report on Form 10-K. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding commodity price risk exposure.
Trading and Non-Trading Marketing Activities
The following table detailing Exelon’s, Generation’s and ComEd’s trading and non-trading marketing activities are 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 and ComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, 2019 to June 30, 2020. 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 11 — 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, 2020 and December 31, 2019.
 
Exelon
 
Generation
 
ComEd
Total mark-to-market energy contract net assets (liabilities) at December 31, 2019(a)
$
567

 
$
868

 
$
(301
)
Total change in fair value during 2020 of contracts recorded in results of operations
(182
)
 
(182
)
 
—

Reclassification to realized at settlement of contracts recorded in results of operations
385

 
385

 
—

Changes in fair value — recorded through regulatory assets(b)
(17
)
 
—

 
(17
)
Changes in allocated collateral
(353
)
 
(353
)
 
—

Net option premium paid
102

 
102

 
—

Option premium amortization
(27
)
 
(27
)
 
—

Upfront payments and amortizations(c)
(50
)
 
(50
)
 
—

Total mark-to-market energy contract net assets (liabilities) at June 30, 2020(a)
$
425

 
$
743

 
$
(318
)
_________
(a)
Amounts are shown net of collateral paid to and received from counterparties.
(b)
For ComEd, the changes in fair value are recorded as a change in regulatory assets. As of June 30, 2020, ComEd recorded a regulatory asset of $318 million related to its mark-to-market derivative liabilities with unaffiliated suppliers. For the six months ended June 30, 2020, ComEd recorded $35 million of decreases in fair value and an increase for realized losses due to settlements of $18 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.
(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 13 — 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
 
2020
 
2021
 
2022
 
2023
 
2024
 
2025 and Beyond
 
Normal Operations, Commodity derivative contracts(a)(b):
 
 
 
 
 
 
 
 
 
 
 
 
 
Actively quoted prices (Level 1)
$
(72
)
 
$
(11
)
 
$
(20
)
 
$
1

 
$
6

 
$
17

 
$
(79
)
Prices provided by external sources (Level 2)
77

 
35

 
37

 
13

 
—

 
1

 
163

Prices based on model or other valuation methods (Level 3)(c)
203

 
223

 
83

 
3

 
(12
)
 
(159
)
 
341

Total
$
208

 
$
247

 
$
100

 
$
17

 
$
(6
)
 
$
(141
)
 
$
425

_________
(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 $576 million at June 30, 2020.
(c)
Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Generation
 
Maturities Within
 
Total Fair
Value
 
2020
 
2021
 
2022
 
2023
 
2024
 
2025 and Beyond
 
Normal Operations, Commodity derivative contracts(a)(b): 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actively quoted prices (Level 1)
$
(72
)
 
$
(11
)
 
$
(20
)
 
$
1

 
$
6

 
$
17

 
$
(79
)
Prices provided by external sources (Level 2)
77

 
35

 
37

 
13

 
—

 
1

 
163

Prices based on model or other valuation methods (Level 3)
220

 
252

 
112

 
32

 
16

 
27

 
659

Total
$
225

 
$
276

 
$
129

 
$
46

 
$
22

 
$
45

 
$
743

_________
(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 $576 million at June 30, 2020.
ComEd
 
Maturities Within
 
Total Fair
Value
 
2020
 
2021
 
2022
 
2023
 
2024
 
2025 and Beyond
 
Commodity derivative contracts(a): 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prices based on model or other valuation methods (Level 3)(a)
$
(17
)
 
$
(29
)
 
$
(29
)
 
$
(29
)
 
$
(28
)
 
$
(186
)
 
$
(318
)
_________
(a)
Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the

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fair value of contracts at the reporting date. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for detailed discussion of credit risk.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchases and normal sales agreements, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2020. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs and commodity exchanges, which are discussed below.
Rating as of June 30, 2020
 
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
 
$
772

 
$
25

 
$
747

 
$
1

 
$
117

Non-investment grade
 
35

 
26

 
9

 


 


No external ratings
 
 
 
 
 
 
 
 
 
 
Internally rated — investment grade
 
213

 
1

 
212

 


 


Internally rated — non-investment grade
 
130

 
17

 
113

 


 


Total
 
$
1,150

 
$
69

 
$
1,081

 
$
1

 
$
117

 
 
Maturity of Credit Risk Exposure
Rating as of June 30, 2020
 
Less than
2 Years
 
2-5 Years
 
Exposure
Greater than
5 Years
 
Total Exposure
Before Credit
Collateral
Investment grade
 
$
690

 
$
55

 
$
27

 
$
772

Non-investment grade
 
35

 
—

 
—

 
35

No external ratings
 
 
 
 
 
 
 
 
Internally rated — investment grade
 
156

 
32

 
25

 
213

Internally rated — non-investment grade
 
118

 
6

 
6

 
130

Total
 
$
999

 
$
93

 
$
58

 
$
1,150

Net Credit Exposure by Type of Counterparty
 
As of
June 30, 2020
Financial institutions
 
$
29

Investor-owned utilities, marketers, power producers
 
834

Energy cooperatives and municipalities
 
173

Other
 
45

Total
 
$
1,081

_________
(a)
As of June 30, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $38 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 2019 Annual Report on Form 10-K.

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See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding credit exposure to suppliers.
Credit-Risk-Related Contingent Features (All Registrants)
Generation
As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase of electricity, natural gas and other commodities. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.
Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s financial statements. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See Note 16 — Debt and Credit Agreements of Exelon’s 2019 Annual Report on Form 10-K for additional information.
Utility Registrants
As of June 30, 2020, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Interest Rate and Foreign Exchange Risk (Exelon and Generation)
Exelon and Generation use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon and Generation may also utilize interest rate swaps to manage their interest rate exposure. A hypothetical 50 basis points increase in the interest rates associated with unhedged variable-rate debt (excluding commercial paper) and fixed-to-floating swaps would result in approximately a $2 million decrease in Exelon pre-tax income for the six months ended June 30, 2020. 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 11 — 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, 2020, Generation’s NDT funds are reflected at fair value in its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy. A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would result in a $696 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.

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Item 4.    Controls and Procedures
During the second quarter of 2020, each of the Registrants' 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 the 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, 2020, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. The 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 were no changes in internal control over financial reporting during the second quarter of 2020 that materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting, including no changes resulting from COVID-19. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview for additional information on COVID-19.
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 2019 Form 10-K and (b) Notes 2 — Regulatory Matters and 14 — 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, 2020, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2019 Form 10-K in ITEM 1A. RISK FACTORS, except for the following risk factors, which were added.
Our Results Could be Negatively Affected by the Impacts of COVID-19 (All Registrants).
The Registrants have taken steps to mitigate the potential risks posed by COVID-19. This is an evolving situation that could lead to extended disruption of economic activity in the Registrants’ respective markets. COVID-19 could negatively affect the Registrants’ ability to operate their respective generating and transmission and distribution assets, their ability to access capital markets, and results of operations. The Registrants cannot predict the extent of the impacts of COVID-19, which will depend on future developments and which are highly uncertain at this time. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview for additional information on COVID-19.
Exelon and ComEd have received requests for information related to an SEC investigation into their lobbying activities. The outcome of the investigation could have a material adverse effect on their reputation and consolidated financial statements (Exelon and ComEd).
On October 22, 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the State of Illinois. Exelon and ComEd have cooperated fully, including by providing all information

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requested by the SEC, and intend to continue to cooperate fully and expeditiously with the SEC. The outcome of the SEC’s investigation cannot be predicted and could subject Exelon and ComEd to criminal or civil penalties, sanctions or other remedial measures.  Any of the foregoing, as well as the appearance of non-compliance with anti-corruption and anti-bribery laws, could have an adverse impact on Exelon’s and ComEd’s reputations or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements. 
If ComEd violates its Deferred Prosecution Agreement announced on July 17, 2020, it could have an adverse effect on the reputation and consolidated financial statements of Exelon and ComEd (Exelon and ComEd).
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and the investigation by the USAO into Exelon’s activities ends with no charges being brought against Exelon. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including, but not limited to, the following: (i) payment to the United States Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date; (ii) continued full cooperation with the government’s investigation; and (iii) ComEd’s adoption and maintenance of remedial measures involving compliance and reporting undertakings as specified in the DPA. If ComEd is found to have breached the terms of the DPA, the USAO may elect to prosecute, or bring a civil action against, ComEd for conduct alleged in the DPA or known to the government, which could result in fines or penalties and could have an adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements.


Item 4.    Mine Safety Disclosures
All Registrants
Not applicable to the Registrants.
Item 5.    Other Information
Amendments to Exelon, ComEd, PECO, BGE and PHI Governing Documents
On August 3, 2020, Exelon, ComEd, PECO, and BGE each adopted Amended and Restated Bylaws, and PHI entered into an Amended and Restated Limited Liability Company Agreement, to address certain administrative and other non-material matters. In addition, the amendments to each of the utilities’ governing documents provide that vacancies on the utilities’ respective boards of directors may only be filled by such utility’s shareholders and that the utilities’ respective governing documents may only be amended by such utility’s shareholders.
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.

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Exhibit
No.
Description

 
 
 
 
 
 

 
 

 
 
 
 


 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 


 
 

 
 
101.INS
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
 
 
101.SCH
Inline XBRL Taxonomy Extension Schema Document.
 
 
101.CAL
Inline XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
101.DEF
Inline XBRL Taxonomy Extension Definition Linkbase Document.


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101.LAB
Inline XBRL Taxonomy Extension Labels Linkbase Document.
 
 
101.PRE
Inline XBRL Taxonomy Extension Presentation Linkbase Document.

 
 
104
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
 

*Filed herewith
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2020 filed by the following officers for the following companies:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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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, 2020 filed by the following officers for the following companies:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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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/    CHRISTOPHER M. CRANE
 
/s/    JOSEPH NIGRO
Christopher M. Crane
 
Joseph Nigro
President and Chief Executive Officer
(Principal Executive Officer) and Director
 
Senior Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
 
 
 
/s/    FABIAN E. SOUZA
 
 
Fabian E. Souza
 
 
Senior Vice President and Corporate Controller
(Principal Accounting Officer)
 
 
August 4, 2020

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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.
EXELON GENERATION COMPANY, LLC
 
/s/    KENNETH W. CORNEW
 
/s/    BRYAN P. WRIGHT
Kenneth W. Cornew
 
Bryan P. Wright
President and Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
 
 
 
/s/    MATTHEW N. BAUER
 
 
Matthew N. Bauer
 
 
Vice President and Controller
(Principal Accounting Officer)
 
 
August 4, 2020

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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.
COMMONWEALTH EDISON COMPANY
 
/s/    JOSEPH DOMINGUEZ
 
/s/    JEANNE M. JONES
Joseph Dominguez
 
Jeanne M. Jones
Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
 
 
 
/s/    GERALD J. KOZEL
 
 
Gerald J. Kozel
 
 
Vice President and Controller
(Principal Accounting Officer)
 
 
August 4, 2020

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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/    MICHAEL A. INNOCENZO
 
/s/    ROBERT J. STEFANI
Michael A. Innocenzo
 
Robert J. Stefani
President and Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
 
 
 
/s/    CAROLINE FULGINITI

 
 
Caroline Fulginiti
 
 
Director, Accounting
(Principal Accounting Officer)
 
 
August 4, 2020


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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/    CARIM V. KHOUZAMI
 
/s/    DAVID M. VAHOS
Carim V. Khouzami
 
David M. Vahos
Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
 
 
 
 /s/ JASON T. JONES
 
 
Jason T. Jones
 
 
Director, Accounting
(Principal Accounting Officer)
 
 
August 4, 2020


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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.
PEPCO HOLDINGS LLC

/s/ DAVID M. VELAZQUEZ
 
/s/    PHILLIP S. BARNETT
David M. Velazquez
 
Phillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
 
 
 
/s/ JULIE E. GIESE
 
 
Julie E. Giese
 
 
Director, Accounting
(Principal Accounting Officer)
 
 
August 4, 2020


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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.
POTOMAC ELECTRIC POWER COMPANY

/s/ DAVID M. VELAZQUEZ
 
/s/    PHILLIP S. BARNETT
David M. Velazquez
 
Phillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
 
 
 
/s/ JULIE E. GIESE
 
 
Julie E. Giese
 
 
Director, Accounting
(Principal Accounting Officer)
 
 
August 4, 2020


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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/ DAVID M. VELAZQUEZ
 
/s/    PHILLIP S. BARNETT
David M. Velazquez
 
Phillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
 
 
 
/s/ JULIE E. GIESE
 
 
Julie E. Giese
 
 
Director, Accounting
(Principal Accounting Officer)
 
 
August 4, 2020


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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/ DAVID M. VELAZQUEZ
 
/s/    PHILLIP S. BARNETT
David M. Velazquez
 
Phillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
 
 
 
/s/ JULIE E. GIESE
 
 
Julie E. Giese
 
 
Director, Accounting
(Principal Accounting Officer)
 
 
August 4, 2020

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