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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 September 30, 2019
or
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission
File Number
 
Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number
 
IRS Employer Identification Number
 
 
 
 
 
001-16169
 
EXELON CORPORATION
 
23-2990190
 
 
(a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago, Illinois 60680-5379
(800) 483-3220
 
 
 
 
 
 
 
333-85496
 
EXELON GENERATION COMPANY, LLC
 
23-3064219
 
 
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348-2473
(610) 765-5959
 
 
 
 
 
 
 
001-01839
 
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 September 30, 2019 was:
Exelon Corporation Common Stock, without par value
972,108,865
Exelon Generation Company, LLC
not applicable
Commonwealth Edison Company Common Stock, $12.50 par value
127,021,343
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
PCI
 
Potomac Capital Investment Corporation and its subsidiaries
Pepco Energy Services or PES
 
Pepco Energy Services, Inc. and its subsidiaries
PHI Corporate
 
PHI in its corporate capacity as a holding company
PHISCO
 
PHI Service Company
SolGen
 
SolGen, LLC
TMI
 
Three Mile Island nuclear facility

4
Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
 
 
Note "—" of the 2018 Form 10-K
 
Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2018 Annual Report on Form 10-K
AESO
 
Alberta Electric Systems Operator
AFUDC
 
Allowance for Funds Used During Construction
AMI
 
Advanced Metering Infrastructure
AOCI
 
Accumulated Other Comprehensive Income (Loss)
ARC
 
Asset Retirement Cost
ARO
 
Asset Retirement Obligation
BGS
 
Basic Generation Service
CERCLA
 
Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CES
 
Clean Energy Standard
Clean Air Act
 
Clean Air Act of 1963, as amended
Clean Water Act
 
Federal Water Pollution Control Amendments of 1972, as amended
CODM
 
Chief operating decision maker(s)
D.C. Circuit Court
 
United States Court of Appeals for the District of Columbia Circuit
DC PLUG
 
District of Columbia Power Line Undergrounding Initiative
DCPSC
 
Public Service Commission of the District of Columbia
DOE
 
United States Department of Energy
DOEE
 
Department of Energy & Environment
DOJ
 
United States Department of Justice
DPSC
 
Delaware Public Service Commission
EDF
 
Electricite de France SA and its subsidiaries
EIMA
 
Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EPA
 
United States Environmental Protection Agency
EPSA
 
Electric Power Supply Association
ERCOT
 
Electric Reliability Council of Texas
FASB
 
Financial Accounting Standards Board
FEJA
 
Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC
 
Federal Energy Regulatory Commission
FRCC
 
Florida Reliability Coordinating Council
GAAP
 
Generally Accepted Accounting Principles in the United States
GCR
 
Gas Cost Rate
GSA
 
Generation Supply Adjustment
ICC
 
Illinois Commerce Commission
ICE
 
Intercontinental Exchange
Illinois EPA
 
Illinois Environmental Protection Agency
IPA
 
Illinois Power Agency
IRC
 
Internal Revenue Code
IRS
 
Internal Revenue Service

5
Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
 
 
ISO
 
Independent System Operator
ISO-NE
 
Independent System Operator New England Inc.
ISO-NY
 
Independent System Operator New York
LIBOR
 
London Interbank Offered Rate
MDE
 
Maryland Department of the Environment
MDPSC
 
Maryland Public Service Commission
MGP
 
Manufactured Gas Plant
MISO
 
Midcontinent Independent System Operator, Inc.
mmcf
 
Million Cubic Feet
MOPR
 
Minimum Offer Price Rule
MW
 
Megawatt
NAAQS
 
National Ambient Air Quality Standards
NDT
 
Nuclear Decommissioning Trust
NEIL
 
Nuclear Electric Insurance Limited
NERC
 
North American Electric Reliability Corporation
NJBPU
 
New Jersey Board of Public Utilities
Non-Regulatory Agreements Units
 
Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOSA
 
Nuclear Operating Services Agreement
NPNS
 
Normal Purchase Normal Sale scope exception
NRC
 
Nuclear Regulatory Commission
NYMEX
 
New York Mercantile Exchange
NYPSC
 
New York Public Service Commission
OCI
 
Other Comprehensive Income
OIESO
 
Ontario Independent Electricity System Operator
OPEB
 
Other Postretirement Employee Benefits
Oyster Creek
 
Oyster Creek Generating Station
PA DEP
 
Pennsylvania Department of Environmental Protection
PAPUC
 
Pennsylvania Public Utility Commission
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
RNF
 
Revenues Net of Purchased Power and Fuel Expense

6
Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
 
 
Regulatory Agreement Units
 
Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
Rider
 
Reconcilable Surcharge Recovery Mechanism
RMC
 
Risk Management Committee
ROE
 
Return on equity
ROU
 
Right-of-use
RSSA
 
Reliability Support Services Agreement
RTO
 
Regional Transmission Organization
SEC
 
United States Securities and Exchange Commission
SERC
 
SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SNF
 
Spent Nuclear Fuel
SOS
 
Standard Offer Service
TCJA
 
Tax Cuts and Jobs Act
Transition Bonds
 
Transition Bonds issued by ACE Funding
Upstream
 
Natural gas exploration and production activities
VIE
 
Variable Interest Entity
WECC
 
Western Electric Coordinating Council
ZEC
 
Zero Emission Credit, or Zero Emission Certificate
ZES
 
Zero Emission Standard

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. The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the Registrants' combined 2018 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 22, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, 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 16, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE TO FIND MORE INFORMATION
The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and the Registrants' website at www.exeloncorp.com. Information contained on the Registrants' website shall not be deemed incorporated into, or to be a part of, this Report.

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
September 30,
 
Nine Months Ended
September 30,
(In millions, except per share data)
2019
 
2018
 
2019
 
2018
Operating revenues
 
 
 
 
 
 
 
Competitive businesses revenues
$
4,499

 
$
4,971

 
$
13,436

 
$
14,387

Rate-regulated utility revenues
4,510

 
4,457

 
12,758

 
12,824

Revenues from alternative revenue programs
(80
)
 
(25
)
 
(98
)
 
(41
)
Total operating revenues
8,929

 
9,403

 
26,096

 
27,170

Operating expenses
 
 
 
 
 
 
 
Competitive businesses purchased power and fuel
2,648

 
2,977

 
8,142

 
8,542

Rate-regulated utility purchased power and fuel
1,304

 
1,355

 
3,589

 
3,832

Operating and maintenance
2,072

 
2,346

 
6,419

 
7,036

Depreciation and amortization
1,083

 
1,105

 
3,237

 
3,284

Taxes other than income
452

 
469

 
1,316

 
1,342

Total operating expenses
7,559


8,252


22,703


24,036

(Loss) gain on sales of assets and businesses
(17
)
 
(5
)
 
19

 
55

Operating income
1,353


1,146


3,412


3,189

Other income and (deductions)
 
 
 
 

 

Interest expense, net
(403
)
 
(387
)
 
(1,202
)
 
(1,119
)
Interest expense to affiliates
(6
)
 
(6
)
 
(19
)
 
(19
)
Other, net
158

 
194

 
837

 
212

Total other income and (deductions)
(251
)

(199
)

(384
)

(926
)
Income before income taxes
1,102

 
947

 
3,028

 
2,263

Income taxes
172

 
137

 
626

 
262

Equity in losses of unconsolidated affiliates
(170
)
 
(10
)
 
(182
)
 
(22
)
Net income
760


800


2,220


1,979

Net (loss) income attributable to noncontrolling interests
(12
)
 
67

 
56

 
121

Net income attributable to common shareholders
$
772


$
733


$
2,164


$
1,858

Comprehensive income, net of income taxes
 
 
 
 
 
 
 
Net income
$
760

 
$
800

 
$
2,220

 
$
1,979

Other comprehensive income (loss), net of income taxes
 
 
 
 
 
 
 
Pension and non-pension postretirement benefit plans:
 
 
 
 
 
 
 
Prior service benefit reclassified to periodic benefit cost
(16
)
 
(17
)
 
(49
)
 
(50
)
Actuarial loss reclassified to periodic benefit cost
37

 
62

 
111

 
186

Pension and non-pension postretirement benefit plan valuation adjustment
6

 
5

 
(32
)
 
22

Unrealized gain on cash flow hedges
—

 
—

 
—

 
12

Unrealized gain on investments in unconsolidated affiliates
5

 
—

 
1

 
3

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

 
2

 
(4
)
Other comprehensive income
30


52


33


169

Comprehensive income
790


852


2,253


2,148

Comprehensive (loss) income attributable to noncontrolling interests
(9
)
 
67

 
57

 
123

Comprehensive income attributable to common shareholders
$
799

 
$
785

 
$
2,196

 
$
2,025

 
 
 
 
 
 
 
 
Average shares of common stock outstanding:
 
 
 
 
 
 
 
Basic
973

 
968

 
972

 
967

Assumed exercise and/or distributions of stock-based awards
1

 
2

 
1

 
2

Diluted(a)
974

 
970

 
973

 
969

 
 
 
 
 
 
 
 
Earnings per average common share:
 
 
 
 
 
 
 
Basic
$
0.79

 
$
0.76

 
$
2.23

 
$
1.92

Diluted
$
0.79

 
$
0.76

 
$
2.22

 
$
1.92

__________
(a)
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was immaterial for the three and nine months ended September 30, 2019 and approximately 2 million and 3 million for the three and nine months ended September 30, 2018, respectively.

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

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
Cash flows from operating activities
 
 
 
Net income
$
2,220

 
$
1,979

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization
4,393

 
4,511

Asset impairments
174

 
49

Gain on sales of assets and businesses
(15
)
 
(55
)
Deferred income taxes and amortization of investment tax credits
412

 
97

Net fair value changes related to derivatives
96

 
67

Net realized and unrealized gains on NDT funds
(467
)
 
(21
)
Other non-cash operating activities
460

 
804

Changes in assets and liabilities:
 
 
 
Accounts receivable
445

 
(167
)
Inventories
(94
)
 
(24
)
Accounts payable and accrued expenses
(671
)
 
84

Option premiums received (paid), net
13

 
(36
)
Collateral (posted) received, net
(254
)
 
222

Income taxes
143

 
166

Pension and non-pension postretirement benefit contributions
(377
)
 
(362
)
Other assets and liabilities
(1,079
)
 
(639
)
Net cash flows provided by operating activities
5,399


6,675

Cash flows from investing activities
 
 
 
Capital expenditures
(5,259
)
 
(5,497
)
Proceeds from NDT fund sales
8,443

 
6,379

Investment in NDT funds
(8,437
)
 
(6,553
)
Acquisition of assets and businesses, net
—

 
(57
)
Proceeds from sales of assets and businesses
17

 
90

Other investing activities
21

 
29

Net cash flows used in investing activities
(5,215
)

(5,609
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
430

 
(218
)
Proceeds from short-term borrowings with maturities greater than 90 days
—

 
126

Repayments on short-term borrowings with maturities greater than 90 days
(125
)
 
(1
)
Issuance of long-term debt
1,576

 
2,664

Retirement of long-term debt
(644
)
 
(1,480
)
Dividends paid on common stock
(1,055
)
 
(999
)
Proceeds from employee stock plans
94

 
67

Other financing activities
(63
)
 
(94
)
Net cash flows provided by financing activities
213


65

Increase in cash, cash equivalents and restricted cash
397

 
1,131

Cash, cash equivalents and restricted cash at beginning of period
1,781

 
1,190

Cash, cash equivalents and restricted cash at end of period
$
2,178


$
2,321

 
 
 
 
Supplemental cash flow information
 
 
 
Decrease in capital expenditures not paid
$
(96
)
 
$
(175
)
Increase in PPE related to ARO update
344

 
67


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

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
1,683

 
$
1,349

Restricted cash and cash equivalents
309

 
247

Accounts receivable, net
 
 
 
Customer (net of allowance for uncollectible accounts of $248 and $283 as of September 30, 2019 and December 31, 2018, respectively)
4,188

 
4,607

Other (net of allowance for uncollectible accounts of $49 and $36 as of September 30, 2019 and December 31, 2018, respectively)
1,085

 
1,256

Mark-to-market derivative assets
601

 
804

Unamortized energy contract assets
49

 
48

Inventories, net
 
 
 
Fossil fuel and emission allowances
325

 
334

Materials and supplies
1,458

 
1,351

Regulatory assets
1,194

 
1,222

Assets held for sale
18

 
904

Other
1,296

 
1,238

Total current assets
12,206


13,360

Property, plant and equipment (net of accumulated depreciation and amortization of $23,590 and $22,902 as of September 30, 2019 and December 31, 2018, respectively)
78,593

 
76,707

Deferred debits and other assets
 
 
 
Regulatory assets
8,122

 
8,237

Nuclear decommissioning trust funds
12,706

 
11,661

Investments
471

 
625

Goodwill
6,677

 
6,677

Mark-to-market derivative assets
487

 
452

Unamortized energy contract assets
353

 
372

Other
3,123

 
1,575

Total deferred debits and other assets
31,939


29,599

Total assets(a)
$
122,738


$
119,666


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

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
1,019

 
$
714

Long-term debt due within one year
4,248

 
1,349

Accounts payable
3,348

 
3,800

Accrued expenses
1,877

 
2,112

Payables to affiliates
5

 
5

Regulatory liabilities
400

 
644

Mark-to-market derivative liabilities
239

 
475

Unamortized energy contract liabilities
138

 
149

Renewable energy credit obligation
375

 
344

Liabilities held for sale
11

 
777

Other
1,425

 
1,035

Total current liabilities
13,085

 
11,404

Long-term debt
32,056

 
34,075

Long-term debt to financing trusts
390

 
390

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
12,133

 
11,330

Asset retirement obligations
10,089

 
9,679

Pension obligations
3,712

 
3,988

Non-pension postretirement benefit obligations
2,029

 
1,928

Spent nuclear fuel obligation
1,193

 
1,171

Regulatory liabilities
9,792

 
9,559

Mark-to-market derivative liabilities
416

 
479

Unamortized energy contract liabilities
368

 
463

Other
3,123

 
2,130

Total deferred credits and other liabilities
42,855

 
40,727

Total liabilities(a)
88,386


86,596

Commitments and contingencies

 

Shareholders’ equity
 
 
 
Common stock (No par value, 2,000 shares authorized, 972 shares and 968 shares outstanding at September 30, 2019 and December 31, 2018, respectively)
19,238

 
19,116

Treasury stock, at cost (2 shares at September 30, 2019 and December 31, 2018)
(123
)
 
(123
)
Retained earnings
15,871

 
14,766

Accumulated other comprehensive loss, net
(2,963
)
 
(2,995
)
Total shareholders’ equity
32,023


30,764

Noncontrolling interests
2,329

 
2,306

Total equity
34,352


33,070

Total liabilities and shareholders’ equity
$
122,738


$
119,666

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

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)
 
Nine Months Ended September 30, 2019
(In millions, shares
in thousands)
Issued
Shares
 
Common
Stock
 
Treasury
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 
Total Shareholders'
Equity
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 (loss), net of income taxes
—

 
—

 
—

 
—

 
22

 
(1
)
 
21

Balance, June 30, 2019
973,417

 
$
19,209

 
$
(123
)
 
$
15,452

 
$
(2,990
)
 
$
2,359

 
$
33,907

Net income (loss)
—

 
—

 
—

 
772

 
—

 
(12
)
 
760

Long-term incentive plan activity
207

 
10

 
—

 
—

 
—

 
—

 
10

Employee stock purchase plan issuances
317

 
19

 
—

 
—

 
—

 
—

 
19

Changes in equity of noncontrolling interests
—

 
—

 
—

 
—

 
—

 
(18
)
 
(18
)
Common stock dividends
($0.36/common share)
—

 
—

 
—

 
(353
)
 
—

 
—

 
(353
)
Other comprehensive income net of income taxes
—

 
—

 
—

 
—

 
27

 
—

 
27

Balance, September 30, 2019
973,941

 
$
19,238

 
$
(123
)
 
$
15,871

 
$
(2,963
)
 
$
2,329

 
$
34,352


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

 
Nine Months Ended September 30, 2018
(In millions, shares
in thousands)
Issued
Shares
 
Common
Stock
 
Treasury
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 
Total Shareholders'
Equity
Balance, December 31, 2017
965,168

 
$
18,964

 
$
(123
)
 
$
14,081

 
$
(3,026
)
 
$
2,291

 
$
32,187

Net income
—

 
—

 
—

 
585

 
—

 
51

 
636

Long-term incentive plan activity
1,685

 
(3
)
 
—

 
—

 
—

 
—

 
(3
)
Employee stock purchase plan issuances
361

 
12

 
—

 
—

 
—

 
—

 
12

Changes in equity of noncontrolling interests
—

 
—

 
—

 
—

 
—

 
(9
)
 
(9
)
Common stock dividends
($0.35/common share)
—

 
—

 
—

 
(334
)
 
—

 
—

 
(334
)
Other comprehensive income, net of income taxes
—

 
—

 
—

 
—

 
71

 
1

 
72

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard
—

 
—

 
—

 
14

 
(10
)
 
—

 
4

Balance, March 31, 2018
967,214

 
$
18,973

 
$
(123
)
 
$
14,346

 
$
(2,965
)
 
$
2,334

 
$
32,565

Net income
—

 
—

 
—

 
539

 
—

 
3

 
542

Long-term incentive plan activity
183

 
20

 
—

 
—

 
—

 
—

 
20

Employee stock purchase plan issuances
342

 
15

 
—

 
—

 
—

 
—

 
15

Changes in equity of noncontrolling interests
—

 
—

 
—

 
—

 
—

 
(14
)
 
(14
)
Common stock dividends
($0.35/common share)
—

 
—

 
—

 
(334
)
 
—

 
—

 
(334
)
Other comprehensive income, net of income taxes
—

 
—

 
—

 
—

 
44

 
1

 
45

Balance, June 30, 2018
967,739

 
$
19,008

 
$
(123
)
 
$
14,551

 
$
(2,921
)
 
$
2,324

 
$
32,839

Net Income
—

 
—

 
—

 
733

 
—

 
67

 
800

Long-term incentive plan activity
809

 
15

 
—

 
—

 
—

 
—

 
15

Employee stock purchase plan issuances
294

 
40

 
—

 
—

 
—

 
—

 
40

Changes in equity of noncontrolling interests
—

 
—

 
—

 
—

 
—

 
(23
)
 
(23
)
Common stock dividends
($0.35/common share)
—

 
—

 
—

 
(335
)
 
—

 
—

 
(335
)
Other comprehensive income, net of income taxes
—

 
—

 
—

 
—

 
52

 
—

 
52

Balance, September 30, 2018
968,842

 
$
19,063

 
$
(123
)
 
$
14,949

 
$
(2,869
)
 
$
2,368

 
$
33,388


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
September 30,
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
 
2019
 
2018
Operating revenues
 
 
 
 
 
 
 
Operating revenues
$
4,499

 
$
4,970

 
$
13,436

 
$
14,389

Operating revenues from affiliates
275

 
308

 
844

 
979

Total operating revenues
4,774


5,278


14,280


15,368

Operating expenses
 
 
 
 
 
 
 
Purchased power and fuel
2,648

 
2,977

 
8,141

 
8,542

Purchased power and fuel from affiliates
3

 
3

 
7

 
10

Operating and maintenance
947

 
1,218

 
3,131

 
3,643

Operating and maintenance from affiliates
140

 
152

 
439

 
483

Depreciation and amortization
407

 
468

 
1,221

 
1,383

Taxes other than income
129

 
143

 
394

 
414

Total operating expenses
4,274


4,961


13,333


14,475

(Loss) gain on sales of assets and businesses
(18
)
 
(6
)
 
15

 
48

Operating income
482


311


962


941

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(101
)
 
(93
)
 
(310
)
 
(278
)
Interest expense to affiliates
(8
)
 
(8
)
 
(26
)
 
(27
)
Other, net
128

 
179

 
729

 
164

Total other income and (deductions)
19


78


393


(141
)
Income before income taxes
501

 
389

 
1,355

 
800

Income taxes
87

 
78

 
388

 
110

Equity in losses of unconsolidated affiliates
(170
)
 
(11
)
 
(183
)
 
(23
)
Net income
244


300


784


667

Net (loss) income attributable to noncontrolling interests
(13
)
 
66

 
56

 
120

Net income attributable to membership interest
$
257


$
234


$
728


$
547

Comprehensive income, net of income taxes
 
 
 
 
 
 
 
Net income
$
244

 
$
300

 
$
784

 
$
667

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

 
—

 
—

 
12

Unrealized gain on investments in unconsolidated affiliates
5

 
—

 
1

 
3

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

 
2

 
(4
)
Other comprehensive income
3


2


3


11

Comprehensive income
247


302


787


678

Comprehensive (loss) income attributable to noncontrolling interests
(10
)
 
66

 
57

 
122

Comprehensive income attributable to membership interest
$
257

 
$
236

 
$
730

 
$
556


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)
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
Cash flows from operating activities
 
 
 
Net income
$
784

 
$
667

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization
2,377

 
2,608

Asset impairments
174

 
49

Gain on sales of assets and businesses
(15
)
 
(48
)
Deferred income taxes and amortization of investment tax credits
201

 
(278
)
Net fair value changes related to derivatives
102

 
73

Net realized and unrealized gains on NDT funds
(467
)
 
(21
)
Other non-cash operating activities
(95
)
 
187

Changes in assets and liabilities:

 

Accounts receivable
395

 
126

Receivables from and payables to affiliates, net
(12
)
 
(7
)
Inventories
(36
)
 
(10
)
Accounts payable and accrued expenses
(428
)
 
(59
)
Option premiums received (paid), net
13

 
(36
)
Collateral (posted) received, net
(292
)
 
228

Income taxes
327

 
220

Pension and non-pension postretirement benefit contributions
(165
)
 
(134
)
Other assets and liabilities
(390
)
 
(154
)
Net cash flows provided by operating activities
2,473


3,411

Cash flows from investing activities
 
 
 
Capital expenditures
(1,282
)
 
(1,660
)
Proceeds from NDT fund sales
8,443

 
6,379

Investment in NDT funds
(8,437
)
 
(6,553
)
Acquisition of assets and businesses, net
—

 
(57
)
Proceeds from sales of assets and businesses
17

 
90

Other investing activities
(6
)
 
(5
)
Net cash flows used in investing activities
(1,265
)

(1,806
)
Cash flows from financing activities
 
 
 
Issuance of long-term debt
41

 
14

Retirement of long-term debt
(196
)
 
(100
)
Changes in Exelon intercompany money pool
(100
)
 
(54
)
Distributions to member
(674
)
 
(688
)
Contributions from member
—


54

Other financing activities
(37
)
 
(46
)
Net cash flows used in financing activities
(966
)

(820
)
Increase in cash, cash equivalents and restricted cash
242

 
785

Cash, cash equivalents and restricted cash at beginning of period
903

 
554

Cash, cash equivalents and restricted cash at end of period
$
1,145


$
1,339

 
 
 
 
Supplemental cash flow information
 
 
 
Decrease in capital expenditures not paid
$
(24
)
 
$
(226
)
Increase in PPE related to ARO update
342

 
47


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)
September 30, 2019
 
December 31, 2018
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
1,019

 
$
750

Restricted cash and cash equivalents
126

 
153

Accounts receivable, net
 
 
 
Customer (net of allowance for uncollectible accounts of $75 and $103 as of September 30, 2019 and December 31, 2018, respectively)
2,587

 
2,941

Other (net of allowance for uncollectible accounts of $1 as of both September 30, 2019 and December 31, 2018)
337

 
562

Mark-to-market derivative assets
602

 
804

Receivables from affiliates
166

 
173

Unamortized energy contract assets
49

 
49

Inventories, net
 
 
 
Fossil fuel and emission allowances
243

 
251

Materials and supplies
1,010

 
963

Assets held for sale
18

 
904

Other
1,002

 
883

Total current assets
7,159


8,433

Property, plant and equipment (net of accumulated depreciation and amortization of $11,972 and $12,206 as of September 30, 2019 and December 31, 2018, respectively)
23,591

 
23,981

Deferred debits and other assets
 
 
 
Nuclear decommissioning trust funds
12,706

 
11,661

Investments
248

 
414

Goodwill
47

 
47

Mark-to-market derivative assets
483

 
452

Prepaid pension asset
1,472

 
1,421

Unamortized energy contract assets
352

 
371

Deferred income taxes
11

 
21

Other
1,915

 
755

Total deferred debits and other assets
17,234


15,142

Total assets(a)
$
47,984


$
47,556


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)
September 30, 2019
 
December 31, 2018
LIABILITIES AND EQUITY
 
 
 
Current liabilities
 
 
 
Long-term debt due within one year
$
2,706

 
$
906

Accounts payable
1,583

 
1,847

Accrued expenses
762

 
898

Payables to affiliates
134

 
139

Borrowings from Exelon intercompany money pool
—

 
100

Mark-to-market derivative liabilities
212

 
449

Unamortized energy contract liabilities
21

 
31

Renewable energy credit obligation
374

 
343

Liabilities held for sale
11

 
777

Other
541

 
279

Total current liabilities
6,344

 
5,769

Long-term debt
5,018

 
6,989

Long-term debt to affiliates
889

 
898

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
3,607

 
3,383

Asset retirement obligations
9,855

 
9,450

Non-pension postretirement benefit obligations
885

 
900

Spent nuclear fuel obligation
1,193

 
1,171

Payables to affiliates
2,960

 
2,606

Mark-to-market derivative liabilities
163

 
252

Unamortized energy contract liabilities
11

 
20

Other
1,466

 
610

Total deferred credits and other liabilities
20,140

 
18,392

Total liabilities(a)
32,391

 
32,048

Commitments and contingencies

 

Equity
 
 
 
Member’s equity
 
 
 
Membership interest
9,525

 
9,518

Undistributed earnings
3,778

 
3,724

Accumulated other comprehensive loss, net
(36
)
 
(38
)
Total member’s equity
13,267

 
13,204

Noncontrolling interests
2,326

 
2,304

Total equity
15,593

 
15,508

Total liabilities and equity
$
47,984

 
$
47,556

__________
(a)
Generation’s consolidated assets include $9,443 million and $9,634 million at September 30, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,467 million and $3,480 million at September 30, 2019 and December 31, 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2 — Variable Interest Entities for additional information.

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)
 
Nine Months Ended September 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 (loss), 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

Net income (loss)
—

 
257

 
—

 
(13
)
 
244

Changes in equity of noncontrolling interests
—

 
—

 
—

 
(18
)
 
(18
)
Distributions to member
—

 
(225
)
 
—

 
—

 
(225
)
Balance, September 30, 2019
$
9,525

 
$
3,778

 
$
(36
)
 
$
2,326

 
$
15,593



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

 
Nine Months Ended September 30, 2018
 
Member’s Equity
 
 
 
 
(In millions)
Membership
Interest
 
Undistributed
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 
Total Equity
Balance, December 31, 2017
$
9,357

 
$
4,349

 
$
(37
)
 
$
2,290

 
$
15,959

Net income
—

 
136

 
—

 
50

 
186

Changes in equity of noncontrolling interests
—

 
—

 
—

 
(9
)
 
(9
)
Distributions to member
—

 
(188
)
 
—

 
—

 
(188
)
Other comprehensive income, net of income taxes
—

 
—

 
6

 
1

 
7

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard
—

 
6

 
(3
)
 
—

 
3

Balance, March 31, 2018
$
9,357

 
$
4,303

 
$
(34
)
 
$
2,332

 
$
15,958

Net income
—

 
178

 
—

 
3

 
181

Changes in equity of noncontrolling interests
—

 
—

 
—

 
(13
)
 
(13
)
Distributions to member
—

 
(189
)
 
—

 
—

 
(189
)
Other comprehensive income, net of income taxes
—

 
—

 
1

 
1

 
2

Balance, June 30, 2018
$
9,357

 
$
4,292

 
$
(33
)
 
$
2,323

 
$
15,939

Net income
—

 
234

 
—

 
66

 
300

Changes in equity of noncontrolling interests
—

 
—

 
—

 
(23
)
 
(23
)
Contribution from member
54

 
—

 
—

 
—

 
54

Distributions to member
—

 
(312
)
 
—

 
—

 
(312
)
Other comprehensive income, net of income taxes
—

 
—

 
2

 
—

 
2

Balance, September 30, 2018
$
9,411

 
$
4,214

 
$
(31
)
 
$
2,366

 
$
15,960



See the Combined Notes to Consolidated Financial Statements
21
Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
 
2019
 
2018
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
1,635

 
$
1,609

 
$
4,427

 
$
4,512

Revenues from alternative revenue programs
(56
)
 
(15
)
 
(98
)
 
(27
)
Operating revenues from affiliates
4

 
4

 
13

 
23

Total operating revenues
1,583


1,598


4,342


4,508

Operating expenses
 
 
 
 
 
 
 
Purchased power
494

 
496

 
1,199

 
1,281

Purchased power from affiliate
83

 
123

 
270

 
421

Operating and maintenance
267

 
276

 
771

 
785

Operating and maintenance from affiliate
73

 
61

 
196

 
189

Depreciation and amortization
259

 
237

 
767

 
696

Taxes other than income
80

 
82

 
228

 
238

Total operating expenses
1,256


1,275


3,431


3,610

Gain on sales of assets
1

 
—

 
4

 
5

Operating income
328


323


915


903

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(87
)
 
(82
)
 
(258
)
 
(251
)
Interest expense to affiliates
(4
)
 
(3
)
 
(10
)
 
(10
)
Other, net
8

 
7

 
27

 
21

Total other income and (deductions)
(83
)

(78
)

(241
)

(240
)
Income before income taxes
245

 
245

 
674

 
663

Income taxes
45

 
52

 
130

 
140

Net income
$
200


$
193


$
544


$
523

Comprehensive income
$
200

 
$
193

 
$
544

 
$
523


22
Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
Cash flows from operating activities
 
 
 
Net income
$
544

 
$
523

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
767

 
696

Deferred income taxes and amortization of investment tax credits
115

 
214

Other non-cash operating activities
180

 
187

Changes in assets and liabilities:
 
 
 
Accounts receivable
(38
)
 
(190
)
Receivables from and payables to affiliates, net
(27
)
 
8

Inventories
(16
)
 
4

Accounts payable and accrued expenses
(132
)
 
(38
)
Collateral posted, net
43

 
(10
)
Income taxes
25

 
(65
)
Pension and non-pension postretirement benefit contributions
(71
)
 
(41
)
Other assets and liabilities
(245
)
 
(170
)
Net cash flows provided by operating activities
1,145


1,118

Cash flows from investing activities
 
 
 
Capital expenditures
(1,413
)
 
(1,540
)
Other investing activities
25

 
22

Net cash flows used in investing activities
(1,388
)

(1,518
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
387

 
—

Issuance of long-term debt
400

 
1,350

Retirement of long-term debt
(300
)
 
(840
)
Contributions from parent
187

 
387

Dividends paid on common stock
(380
)
 
(345
)
Other financing activities
(10
)
 
(16
)
Net cash flows provided by financing activities
284


536

Increase in cash, cash equivalents and restricted cash
41

 
136

Cash, cash equivalents and restricted cash at beginning of period
330

 
144

Cash, cash equivalents and restricted cash at end of period
$
371


$
280

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

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

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
76

 
$
135

Restricted cash
124

 
29

Accounts receivable, net
 
 
 
Customer (net of allowance for uncollectible accounts of $65 and $61 as of September 30, 2019 and December 31, 2018, respectively)
561

 
539

Other (net of allowance for uncollectible accounts of $21 and $20 as of September 30, 2019 and December 31, 2018, respectively)
322

 
320

Receivables from affiliates
27

 
20

Inventories, net
162

 
148

Regulatory assets
286

 
293

Other
48

 
86

Total current assets
1,606


1,570

Property, plant and equipment (net of accumulated depreciation and amortization of $5,046 and $4,684 as of September 30, 2019 and December 31, 2018, respectively)
22,795

 
22,058

Deferred debits and other assets
 
 
 
Regulatory assets
1,436

 
1,307

Investments
6

 
6

Goodwill
2,625

 
2,625

Receivables from affiliates
2,487

 
2,217

Prepaid pension asset
1,020

 
1,035

Other
351

 
395

Total deferred debits and other assets
7,925


7,585

Total assets
$
32,326


$
31,213


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

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
387

 
$
—

Long-term debt due within one year
500

 
300

Accounts payable
520

 
607

Accrued expenses
275

 
373

Payables to affiliates
87

 
119

Customer deposits
116

 
111

Regulatory liabilities
193

 
293

Mark-to-market derivative liability
27

 
26

Other
138

 
96

Total current liabilities
2,243

 
1,925

Long-term debt
7,696

 
7,801

Long-term debt to financing trust
205

 
205

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
4,016

 
3,813

Asset retirement obligations
120

 
118

Non-pension postretirement benefits obligations
185

 
201

Regulatory liabilities
6,390

 
6,050

Mark-to-market derivative liability
253

 
223

Other
621

 
630

Total deferred credits and other liabilities
11,585

 
11,035

Total liabilities
21,729

 
20,966

Commitments and contingencies

 

Shareholders’ equity
 
 
 
Common stock
1,588

 
1,588

Other paid-in capital
7,509

 
7,322

Retained deficit unappropriated
(1,639
)
 
(1,639
)
Retained earnings appropriated
3,139

 
2,976

Total shareholders’ equity
10,597

 
10,247

Total liabilities and shareholders’ equity
$
32,326

 
$
31,213


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

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
 
Nine Months Ended September 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

Net income
—

 
—

 
200

 
—

 
200

Appropriation of retained earnings for future dividends
—

 
—

 
(200
)
 
200

 
—

Common stock dividends
—

 
—

 
—

 
(126
)
 
(126
)
Contributions from parent
—

 
63

 
—

 
—

 
63

Balance, September 30, 2019
$
1,588

 
$
7,509

 
$
(1,639
)
 
$
3,139

 
$
10,597

 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
(In millions)
Common
Stock
 
Other
Paid-In
Capital
 
Retained Deficit
Unappropriated
 
Retained
Earnings
Appropriated
 
Total
Shareholders’
Equity
Balance, December 31, 2017
$
1,588

 
$
6,822

 
$
(1,639
)
 
$
2,771

 
$
9,542

Net income
—

 
—

 
165

 
—

 
165

Appropriation of retained earnings for future dividends
—

 
—

 
(165
)
 
165

 
—

Common stock dividends
—

 
—

 
—

 
(114
)
 
(114
)
Contributions from parent
—

 
113

 
—

 
—

 
113

Balance, March 31, 2018
$
1,588

 
$
6,935

 
$
(1,639
)
 
$
2,822

 
$
9,706

Net income
—

 
—

 
164

 
—

 
164

Appropriation of retained earnings for future dividends
—

 
—

 
(164
)
 
164

 
—

Common stock dividends
—

 
—

 
—

 
(115
)
 
(115
)
Contributions from parent
—

 
112

 
—

 
—

 
112

Balance, June 30, 2018
$
1,588

 
$
7,047

 
$
(1,639
)
 
$
2,871

 
$
9,867

Net income
—

 
—

 
193

 
—

 
193

Appropriation of retained earnings for future dividends
—

 
—

 
(193
)
 
193

 
—

Common stock dividends
—

 
—

 
—

 
(115
)
 
(115
)
Contributions from parent
—

 
162

 
—

 
—

 
162

Balance, September 30, 2018
$
1,588

 
$
7,209

 
$
(1,639
)
 
$
2,949

 
$
10,107


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


PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
 
2019
 
2018
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
726

 
$
697

 
$
1,914

 
$
1,886

Natural gas operating revenues
62

 
57

 
431

 
382

Revenues from alternative revenue programs
(11
)
 
1

 
(16
)
 
2

Operating revenues from affiliates
1

 
2

 
4

 
5

Total operating revenues
778


757


2,333


2,275

Operating expenses
 
 
 
 
 
 
 
Purchased power
185

 
215

 
461

 
576

Purchased fuel
18

 
14

 
184

 
148

Purchased power from affiliate
43

 
34

 
122

 
94

Operating and maintenance
182

 
184

 
531

 
572

Operating and maintenance from affiliates
37

 
35

 
112

 
114

Depreciation and amortization
83

 
75

 
247

 
224

Taxes other than income
47

 
46

 
126

 
125

Total operating expenses
595


603


1,783


1,853

Gain on sales of assets
—

 
—

 
—

 
1

Operating income
183


154


550


423

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(30
)
 
(28
)
 
(91
)
 
(85
)
Interest expense to affiliates
(3
)
 
(4
)
 
(9
)
 
(11
)
Other, net
4

 
2

 
11

 
4

Total other income and (deductions)
(29
)

(30
)

(89
)

(92
)
Income before income taxes
154

 
124

 
461


331

Income taxes
14

 
(2
)
 
51

 
(5
)
Net income
$
140


$
126


$
410


$
336

Comprehensive income
$
140

 
$
126

 
$
410

 
$
336


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

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
Cash flows from operating activities
 
 
 
Net income
$
410

 
$
336

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
247

 
224

Gain on sales of assets
—

 
(1
)
Deferred income taxes and amortization of investment tax credits
6

 
5

Other non-cash operating activities
28

 
41

Changes in assets and liabilities:
 
 
 
Accounts receivable
46

 
(85
)
Receivables from and payables to affiliates, net
(12
)
 
1

Inventories
(3
)
 
(13
)
Accounts payable and accrued expenses
(32
)
 
(1
)
Income taxes
(15
)
 
(16
)
Pension and non-pension postretirement benefit contributions
(26
)
 
(25
)
Other assets and liabilities
(111
)
 
26

Net cash flows provided by operating activities
538


492

Cash flows from investing activities
 
 
 
Capital expenditures
(675
)
 
(615
)
Other investing activities
7

 
6

Net cash flows used in investing activities
(668
)

(609
)
Cash flows from financing activities
 
 
 
Issuance of long-term debt
325

 
700

Retirement of long-term debt
—

 
(500
)
Contributions from parent
174

 
71

Dividends paid on common stock
(268
)
 
(300
)
Other financing activities
(6
)
 
(22
)
Net cash flows provided by (used in) financing activities
225


(51
)
Increase (decrease) in cash, cash equivalents and restricted cash
95

 
(168
)
Cash, cash equivalents and restricted cash at beginning of period
135

 
275

Cash, cash equivalents and restricted cash at end of period
$
230


$
107

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

 
$
4


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

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
224

 
$
130

Restricted cash and cash equivalents
6

 
5

Accounts receivable, net
 
 
 
Customer (net of allowance for uncollectible accounts of $54 and $53 as of September 30, 2019 and December 31, 2018, respectively)
286

 
321

Other (net of allowance for uncollectible accounts of $7 and $8 as of September 30, 2019 and December 31, 2018, respectively)
118

 
151

Receivable from affiliates
7

 
—

Inventories, net
 
 
 
Fossil fuel
41

 
38

Materials and supplies
37

 
37

Prepaid utility taxes
34

 
—

Regulatory assets
63

 
81

Other
27

 
19

Total current assets
843


782

Property, plant and equipment (net of accumulated depreciation and amortization of $3,670 and $3,561 as of September 30, 2019 and December 31, 2018, respectively)
9,100

 
8,610

Deferred debits and other assets
 
 
 
Regulatory assets
540

 
460

Investments
26

 
25

Receivable from affiliates
473

 
389

Prepaid pension asset
367

 
349

Other
30

 
27

Total deferred debits and other assets
1,436


1,250

Total assets
$
11,379


$
10,642


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

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
382

 
370

Accrued expenses
97

 
113

Payables to affiliates
54

 
59

Customer deposits
69

 
68

Regulatory liabilities
93

 
175

Other
27

 
24

Total current liabilities
722

 
809

Long-term debt
3,404

 
3,084

Long-term debt to financing trusts
184

 
184

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
2,034

 
1,933

Asset retirement obligations
28

 
27

Non-pension postretirement benefits obligations
289

 
288

Regulatory liabilities
503

 
421

Other
79

 
76

Total deferred credits and other liabilities
2,933

 
2,745

Total liabilities
7,243

 
6,822

Commitments and contingencies

 

Shareholder’s equity
 
 
 
Common stock
2,752

 
2,578

Retained earnings
1,384

 
1,242

Total shareholder’s equity
4,136

 
3,820

Total liabilities and shareholder's equity
$
11,379

 
$
10,642


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

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
 
Nine months ended September 30, 2019
(In millions)
Common
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income, net
 
Total
Shareholder's
Equity
Balance, December 31, 2018
$
2,578

 
$
1,242

 
$
—

 
$
3,820

Net income
—

 
168

 
—

 
168

Common stock dividends
—

 
(90
)
 
—

 
(90
)
Contributions from 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

Net income
—

 
140

 
—

 
140

Common stock dividends
—

 
(88
)
 
—

 
(88
)
Contributions from parent
29

 
—

 
—

 
29

Balance, September 30, 2019
$
2,752

 
$
1,384

 
$
—

 
$
4,136

 
 
 
 
 
 
 
 
 
Nine months ended September 30, 2018
(In millions)
Common
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income, net
 
Total
Shareholder's
Equity
Balance, December 31, 2017
$
2,489

 
$
1,087

 
$
1

 
$
3,577

Net income
—

 
113

 
—

 
113

Common stock dividends
—

 
(287
)
 
—

 
(287
)
Impact of adoption of Recognition and Measurement of Financial Assets and
Liabilities Standard
—

 
1

 
(1
)
 
—

Balance, March 31, 2018
$
2,489

 
$
914

 
$
—

 
$
3,403

Net income
—

 
96

 
—

 
96

Common stock dividends
—

 
(5
)
 
—

 
(5
)
Contributions from parent
41

 
—

 
—

 
41

Balance, June 30, 2018
$
2,530

 
$
1,005

 
$
—

 
$
3,535

Net income
—

 
126

 
—

 
126

Common stock dividends
—

 
(7
)
 
—

 
(7
)
Contributions from parent
30

 
—

 
—

 
30

Balance, September 30, 2018
$
2,560

 
$
1,124

 
$
—

 
$
3,684


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


BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
 
2019
 
2018
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
623

 
$
652

 
$
1,814

 
$
1,847

Natural gas operating revenues
79

 
79

 
484

 
527

Revenues from alternative revenue programs
(5
)
 
(6
)
 
11

 
(23
)
Operating revenues from affiliates
6

 
6

 
18

 
18

Total operating revenues
703


731


2,327


2,369

Operating expenses
 
 
 
 
 
 
 
Purchased power
159

 
183

 
480

 
510

Purchased fuel
12

 
21

 
128

 
176

Purchased power from affiliate
64

 
68

 
196

 
195

Operating and maintenance
157

 
144

 
451

 
462

Operating and maintenance from affiliates
39

 
38

 
118

 
116

Depreciation and amortization
116

 
110

 
368

 
358

Taxes other than income
65

 
64

 
195

 
188

Total operating expenses
612


628


1,936


2,005

Gain on sales of assets
—

 
—

 
—

 
1

Operating income
91


103


391


365

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(31
)
 
(27
)
 
(89
)
 
(78
)
Other, net
7

 
5

 
18

 
14

Total other income and (deductions)
(24
)

(22
)

(71
)

(64
)
Income before income taxes
67

 
81

 
320


301

Income taxes
12

 
18

 
59

 
59

Net income
$
55


$
63


$
261


$
242

Comprehensive income
$
55

 
$
63

 
$
261

 
$
242


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

BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
Cash flows from operating activities
 
 
 
Net income
$
261

 
$
242

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
368

 
358

Deferred income taxes and amortization of investment tax credits
66

 
82

Other non-cash operating activities
63

 
42

Changes in assets and liabilities:
 
 
 
Accounts receivable
110

 
72

Receivables from and payables to affiliates, net
(14
)
 
(4
)
Inventories
(5
)
 
(8
)
Accounts payable and accrued expenses
(28
)
 
(3
)
Collateral (posted) received, net
(5
)
 
1

Income taxes
(43
)
 
(48
)
Pension and non-pension postretirement benefit contributions
(45
)
 
(50
)
Other assets and liabilities
(65
)
 
(9
)
Net cash flows provided by operating activities
663


675

Cash flows from investing activities
 
 
 
Capital expenditures
(842
)
 
(667
)
Other investing activities
4

 
8

Net cash flows used in investing activities
(838
)

(659
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
(35
)
 
(77
)
Issuance of long-term debt
400

 
300

Dividends paid on common stock
(169
)
 
(157
)
Contributions from parent
104

 
18

Other financing activities
(7
)
 
(2
)
Net cash flows provided by financing activities
293


82

Increase in cash, cash equivalents and restricted cash
118

 
98

Cash, cash equivalents and restricted cash at beginning of period
13

 
18

Cash, cash equivalents and restricted cash at end of period
$
131


$
116

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

 
$
44


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

BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
130

 
$
7

Restricted cash and cash equivalents
1

 
6

Accounts receivable, net
 
 
 
Customer (net of allowance for uncollectible accounts of $13 and $16 as of September 30, 2019 and December 31, 2018, respectively)
242

 
353

Other (net of allowance for uncollectible accounts of $4 as of both September 30, 2019 and December 31, 2018)
110

 
90

Receivables from affiliates
1

 
1

Inventories, net
 
 
 
Fossil fuel
34

 
36

Materials and supplies
46

 
39

Prepaid utility taxes
—

 
74

Regulatory assets
180

 
177

Other
7

 
3

Total current assets
751


786

Property, plant and equipment (net of accumulated depreciation and amortization of $3,772 and $3,633 as of September 30, 2019 and December 31, 2018, respectively)
8,796

 
8,243

Deferred debits and other assets
 
 
 
Regulatory assets
386

 
398

Investments
7

 
5

Prepaid pension asset
276

 
279

Other
88

 
5

Total deferred debits and other assets
757


687

Total assets
$
10,304


$
9,716


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

BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
—

 
$
35

Accounts payable
245

 
295

Accrued expenses
165

 
155

Payables to affiliates
51

 
65

Customer deposits
120

 
120

Regulatory liabilities
21

 
77

Other
63

 
27

Total current liabilities
665

 
774

Long-term debt
3,270

 
2,876

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
1,329

 
1,222

Asset retirement obligations
22

 
24

Non-pension postretirement benefits obligations
198

 
201

Regulatory liabilities
1,158

 
1,192

Other
112

 
73

Total deferred credits and other liabilities
2,819

 
2,712

Total liabilities
6,754

 
6,362

Commitments and contingencies

 

Shareholder's equity
 
 
 
Common stock
1,818

 
1,714

Retained earnings
1,732

 
1,640

Total shareholder's equity
3,550

 
3,354

Total liabilities and shareholder's equity
$
10,304

 
$
9,716




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

BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
 
Nine Months Ended September 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

Net income
—

 
55

 
55

Contributions from parent
104

 
—

 
104

Common stock dividends
—

 
(57
)
 
(57
)
Balance, September 30, 2019
$
1,818


$
1,732

 
$
3,550

 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholder's
Equity
Balance, December 31, 2017
$
1,605

 
$
1,536

 
$
3,141

Net income
—

 
128

 
128

Common stock dividends
—

 
(52
)
 
(52
)
Balance, March 31, 2018
$
1,605

 
$
1,612

 
$
3,217

Net income
—

 
51

 
51

Common stock dividends
—

 
(53
)
 
(53
)
Balance, June 30, 2018
$
1,605

 
$
1,610

 
$
3,215

Net income
—

 
63

 
63

Contributions from parent
18

 
—

 
18

Common stock dividends
—

 
(52
)
 
(52
)
Balance, September 30, 2018
$
1,623

 
$
1,621

 
$
3,244


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


PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
 
2019
 
2018
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
1,365

 
$
1,340

 
$
3,570

 
$
3,541

Natural gas operating revenues
20

 
23

 
115

 
129

Revenues from alternative revenue programs
(9
)
 
(5
)
 
4

 
7

Operating revenues from affiliates
4

 
3

 
11

 
11

Total operating revenues
1,380

 
1,361

 
3,700

 
3,688

Operating expenses
 
 
 
 
 
 
 
Purchased power
428

 
415

 
1,086

 
1,077

Purchased fuel
8

 
12

 
51

 
65

Purchased power and fuel from affiliates
83

 
82

 
254

 
268

Operating and maintenance
254

 
261

 
706

 
751

Operating and maintenance from affiliates
36

 
31

 
105

 
106

Depreciation and amortization
193

 
192

 
562

 
555

Taxes other than income
122

 
123

 
342

 
343

Total operating expenses
1,124

 
1,116

 
3,106

 
3,165

Operating income
256

 
245


594

 
523

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(66
)
 
(65
)
 
(197
)
 
(193
)
Other, net
13

 
11

 
39

 
33

Total other income and (deductions)
(53
)
 
(54
)
 
(158
)
 
(160
)
Income before income taxes
203

 
191

 
436

 
363

Income taxes
14

 
4

 
25

 
28

Equity in earnings of unconsolidated affiliate
—

 
—

 
1

 
1

Net income
$
189

 
$
187

 
$
412

 
$
336

Comprehensive income
$
189

 
$
187

 
$
412

 
$
336


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

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
Cash flows from operating activities
 
 

Net income
$
412

 
$
336

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
562

 
555

Deferred income taxes and amortization of investment tax credits
8

 
50

Other non-cash operating activities
122

 
109

Changes in assets and liabilities:
 
 
 
Accounts receivable
(64
)
 
(89
)
Receivables from and payables to affiliates, net
1

 
10

Inventories
(36
)
 
—

Accounts payable and accrued expenses
—

 
115

Income taxes
(11
)
 
(31
)
Pension and non-pension postretirement benefit contributions
(15
)
 
(66
)
Other assets and liabilities
(102
)
 
(144
)
Net cash flows provided by operating activities
877

 
845

Cash flows from investing activities
 
 
 
Capital expenditures
(1,006
)
 
(988
)
Other investing activities
3

 
2

Net cash flows used in investing activities
(1,003
)

(986
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
78

 
(141
)
Proceeds from short-term borrowings with maturities greater than 90 days
—

 
125

Repayments of short-term borrowings with maturities greater than 90 days
(125
)
 
—

Issuance of long-term debt
410

 
300

Retirement of long-term debt
(130
)
 
(33
)
Change in Exelon intercompany money pool
10

 
10

Distributions to member
(429
)
 
(232
)
Contributions from member
283

 
237

Other financing activities
(5
)
 
(6
)
Net cash flows provided by financing activities
92

 
260

(Decrease) increase in cash, cash equivalents and restricted cash
(34
)
 
119

Cash, cash equivalents and restricted cash at beginning of period
186

 
95

Cash, cash equivalents and restricted cash at end of period
$
152

 
$
214

 
 
 
 
Supplemental cash flow information
 
 
 
(Decrease) increase in capital expenditures not paid
$
(62
)
 
$
54


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

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
99

 
$
124

Restricted cash and cash equivalents
38

 
43

Accounts receivable, net
 
 
 
Customer (net of allowance for uncollectible accounts of $41 and $50 as of September 30, 2019 and December 31, 2018, respectively)
512

 
453

Other (net of allowance for uncollectible accounts of $16 and $3 as of September 30, 2019 and December 31, 2018, respectively)
189

 
177

Inventories, net
 
 
 
Fossil Fuel
8

 
9

Materials and supplies
203

 
163

Regulatory assets
479

 
489

Other
50

 
75

Total current assets
1,578


1,533

Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,124 and $841 as of September 30, 2019 and December 31, 2018, respectively)
13,968

 
13,446

Deferred debits and other assets
 
 
 
Regulatory assets
2,095

 
2,312

Investments
135

 
130

Goodwill
4,005

 
4,005

Prepaid pension asset
426

 
486

Deferred income taxes
13

 
12

Other
356

 
60

Total deferred debits and other assets
7,030


7,005

Total assets(a)
$
22,576


$
21,984


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

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
LIABILITIES AND MEMBER'S EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
132

 
$
179

Long-term debt due within one year
118

 
125

Accounts payable
416

 
496

Accrued expenses
279

 
256

Payables to affiliates
95

 
94

Borrowings from Exelon intercompany money pool
10

 
—

Customer deposits
118

 
116

Regulatory liabilities
78

 
84

Unamortized energy contract liabilities
117

 
119

Other
152

 
123

Total current liabilities
1,515

 
1,592

Long-term debt
6,376

 
6,134

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
2,289

 
2,146

Asset retirement obligations
57

 
52

Non-pension postretirement benefit obligations
99

 
103

Regulatory liabilities
1,725

 
1,864

Unamortized energy contract liabilities
357

 
442

Other
610

 
369

Total deferred credits and other liabilities
5,137

 
4,976

Total liabilities(a)
13,028

 
12,702

Commitments and contingencies

 

Member's equity
 
 
 
Membership interest
9,503

 
9,220

Undistributed earnings
45

 
62

Total member's equity
9,548


9,282

Total liabilities and member's equity
$
22,576


$
21,984

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

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

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
 
Nine Months Ended September 30, 2019
(In millions)
Membership Interest
 
Undistributed Earnings (Losses)
 
Member's Equity
Balance, December 31, 2018
$
9,220

 
$
62

 
$
9,282

Net income
—

 
117

 
117

Distributions to member
—

 
(128
)
 
(128
)
Contributions from 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

Net income
—


189

 
189

Distributions to member
—


(213
)
 
(213
)
Balance, September 30, 2019
$
9,503

 
$
45

 
$
9,548

 
Nine Months Ended September 30, 2018
(In millions)
Membership Interest
 
Undistributed Earnings (Losses)
 
Member's Equity
Balance, December 31, 2017
$
8,835

 
$
(10
)
 
$
8,825

Net income
—

 
65

 
65

Distributions to member
—

 
(71
)
 
(71
)
Balance, March 31, 2018
$
8,835

 
$
(16
)
 
$
8,819

Net income
—

 
84

 
84

Distributions to member
—

 
(38
)
 
(38
)
Contributions from member
235

 
—

 
235

Balance, June 30, 2018
$
9,070

 
$
30

 
$
9,100

Net income
—


187


187

Distribution to member
—


(123
)

(123
)
Contribution from parent
2


—


2

Balance, September 30, 2018
$
9,072


$
94


$
9,166


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


POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 
Three Months Ended
September 30,

Nine Months Ended
September 30,
(In millions)
2019

2018

2019

2018
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
643

 
$
630

 
$
1,733

 
$
1,697

Revenues from alternative revenue programs
(3
)
 
(4
)
 
10

 
6

Operating revenues from affiliates
2

 
2

 
5

 
5

Total operating revenues
642

 
628

 
1,748

 
1,708

Operating expenses
 
 
 
 
 
 
 
Purchased power
116

 
131

 
325

 
354

Purchased power from affiliates
65

 
46

 
188

 
143

Operating and maintenance
85

 
84

 
208

 
216

Operating and maintenance from affiliates
50

 
52

 
156

 
167

Depreciation and amortization
95

 
99

 
281

 
286

Taxes other than income
104

 
104

 
286

 
288

Total operating expenses
515

 
516

 
1,444

 
1,454

Operating income
127

 
112

 
304

 
254

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(33
)
 
(32
)
 
(100
)
 
(96
)
Other, net
9

 
7

 
22

 
23

Total other income and (deductions)
(24
)
 
(25
)
 
(78
)
 
(73
)
Income before income taxes
103

 
87

 
226

 
181

Income taxes
5

 
(2
)
 
9

 
7

Net income
$
98

 
$
89

 
$
217

 
$
174

Comprehensive income
$
98

 
$
89

 
$
217

 
$
174


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

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
Cash flows from operating activities
 
 
 
Net income
$
217

 
$
174

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
281

 
286

Deferred income taxes and amortization of investment tax credits
12

 
(5
)
Other non-cash operating activities
43

 
42

Changes in assets and liabilities:
 
 
 
Accounts receivable
(49
)
 
(36
)
Receivables from and payables to affiliates, net
4

 
(9
)
Inventories
(23
)
 
6

Accounts payable and accrued expenses
(12
)
 
104

Income taxes
(23
)
 
(18
)
Pension and non-pension postretirement benefit contributions
(10
)
 
(11
)
Other assets and liabilities
(55
)
 
(137
)
Net cash flows provided by operating activities
385

 
396

Cash flows from investing activities
 
 
 
Capital expenditures
(455
)
 
(475
)
Other investing activities
2

 
3

Net cash flows used in investing activities
(453
)
 
(472
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
(28
)
 
38

Issuance of long-term debt
260

 
100

Retirement of long-term debt
(118
)
 
(8
)
Dividends paid on common stock
(173
)
 
(128
)
Contributions from parent
129

 
85

Other financing activities
(3
)
 
(4
)
Net cash flows provided by financing activities
67

 
83

(Decrease) increase in cash, cash equivalents and restricted cash
(1
)
 
7

Cash, cash equivalents and restricted cash at beginning of period
53

 
40

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

 
$
47

 
 
 
 
Supplemental cash flow information
 
 
 
(Decrease) increase in capital expenditures not paid
$
(7
)
 
$
15


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

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019

December 31, 2018
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
18

 
$
16

Restricted cash and cash equivalents
34

 
37

Accounts receivable, net
 
 
 
Customer (net of allowance for uncollectible accounts of $16 and $20 as of September 30, 2019 and December 31, 2018, respectively)
258

 
225

Other (net of allowance for uncollectible accounts of $8 and $1 as of September 30, 2019 and December 31, 2018, respectively)
114

 
81

Receivables from affiliates
—

 
1

Inventories, net
118

 
93

Regulatory assets
252

 
270

Other
12

 
37

Total current assets
806


760

Property, plant and equipment, net (net of accumulated depreciation and amortization of $3,473 and $3,354 as of September 30, 2019 and December 31, 2018, respectively)
6,734

 
6,460

Deferred debits and other assets
 
 
 
Regulatory assets
577

 
643

Investments
109

 
105

Prepaid pension asset
301

 
316

Other
76

 
15

Total deferred debits and other assets
1,063


1,079

Total assets
$
8,603


$
8,299


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

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
12

 
$
40

Long-term debt due within one year
8

 
15

Accounts payable
177

 
214

Accrued expenses
144

 
126

Payables to affiliates
65

 
62

Customer deposits
56

 
54

Regulatory liabilities
9

 
7

Merger related obligation
38

 
38

Current portion of DC PLUG obligation
30

 
30

Other
25

 
42

Total current liabilities
564


628

Long-term debt
2,852

 
2,704

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
1,150

 
1,064

Asset retirement obligations
41

 
37

Non-pension postretirement benefit obligations
23

 
29

Regulatory liabilities
749

 
822

Other
311

 
275

Total deferred credits and other liabilities
2,274


2,227

Total liabilities
5,690


5,559

Commitments and contingencies

 

Shareholder's equity
 
 
 
Common stock
1,765

 
1,636

Retained earnings
1,148

 
1,104

Total shareholder's equity
2,913

 
2,740

Total liabilities and shareholder's equity
$
8,603

 
$
8,299


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

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
 
Nine Months Ended September 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

Net income
—

 
98

 
98

Common stock dividends
—

 
(101
)
 
(101
)
Balance, September 30, 2019
$
1,765


$
1,148


$
2,913

 
Nine Months Ended September 30, 2018
(In millions)
Common Stock
 
Retained Earnings
 
Total Shareholder's Equity
Balance, December 31, 2017
$
1,470

 
$
1,063

 
$
2,533

Net income
—

 
31

 
31

Common stock dividends
—

 
(25
)
 
(25
)
Balance, March 31, 2018
$
1,470

 
$
1,069

 
$
2,539

Net income
—

 
54

 
54

Common stock dividends
—

 
(25
)
 
(25
)
Contributions from parent
85

 
—

 
85

Balance, June 30, 2018
$
1,555

 
$
1,098

 
$
2,653

Net income
—

 
89

 
89

Common stock dividends
—

 
(78
)
 
(78
)
Balance, September 30, 2018
$
1,555

 
$
1,109

 
$
2,664



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


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

Nine Months Ended
September 30,
(In millions)
2019

2018

2019

2018
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
304

 
$
302

 
$
872

 
$
861

Natural gas operating revenues
20

 
24

 
116

 
129

Revenues from alternative revenue programs
(6
)
 
—

 
(6
)
 
5

Operating revenues from affiliates
1

 
2

 
5

 
6

Total operating revenues
319


328


987


1,001

Operating expenses
 
 
 
 
 
 
 
Purchased power
105

 
96

 
298

 
258

Purchased fuel
8

 
11

 
51

 
64

Purchased power from affiliate
14

 
26

 
50

 
103

Operating and maintenance
43

 
44

 
127

 
137

Operating and maintenance from affiliates
37

 
38

 
113

 
119

Depreciation and amortization
46

 
47

 
138

 
135

Taxes other than income
15

 
15

 
43

 
43

Total operating expenses
268


277


820


859

Operating income
51


51


167


142

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(15
)
 
(15
)
 
(45
)
 
(42
)
Other, net
2

 
2

 
10

 
7

Total other income and (deductions)
(13
)

(13
)

(35
)

(35
)
Income before income taxes
38

 
38

 
132

 
107

Income taxes
5

 
5

 
16

 
17

Net income
$
33


$
33


$
116


$
90

Comprehensive income
$
33

 
$
33

 
$
116

 
$
90


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

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
 
Nine Months Ended
September 30,
(In millions)
2019

2018
Cash flows from operating activities
 
 
 
Net income
$
116

 
$
90

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
138

 
135

Deferred income taxes and amortization of investment tax credits
(2
)
 
24

Other non-cash operating activities
21

 
16

Changes in assets and liabilities:
 
 
 
Accounts receivable
29

 
13

Receivables from and payables to affiliates, net
(7
)
 
(14
)
Inventories
(7
)
 
(3
)
Accounts payable and accrued expenses
3

 
18

Income taxes
11

 
—

Pension and non-pension postretirement benefit contributions
(1
)
 
—

Other assets and liabilities
(22
)
 
13

Net cash flows provided by operating activities
279


292

Cash flows from investing activities
 
 
 
Capital expenditures
(245
)
 
(254
)
Other investing activities
1

 
1

Net cash flows used in investing activities
(244
)

(253
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
57

 
(216
)
Issuance of long-term debt
—

 
200

Retirement of long-term debt
—

 
(4
)
Dividends paid on common stock
(105
)
 
(58
)
Contributions from parent
—

 
150

Other financing activities
—

 
(3
)
Net cash flows (used in) provided by financing activities
(48
)

69

(Decrease) increase in cash, cash equivalents and restricted cash
(13
)
 
108

Cash, cash equivalents and restricted cash at beginning of period
24

 
2

Cash, cash equivalents and restricted cash at end of period
$
11


$
110

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


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

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
11

 
$
23

Restricted cash and cash equivalents
—

 
1

Accounts receivable, net
 
 
 
Customer (net of allowance for uncollectible accounts of $10 and $12 as of September 30, 2019 and December 31, 2018, respectively)
112

 
134

Other (net of allowance for uncollectible accounts of $1 as of both September 30, 2019 and December 31, 2018)
37

 
46

Inventories, net
 
 
 
Fossil Fuel
8

 
9

Materials and supplies
47

 
37

Prepaid utility taxes
15

 
17

Regulatory assets
62

 
59

Other
5

 
10

Total current assets
297


336

Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,407 and $1,329 as of September 30, 2019 and December 31, 2018, respectively)
3,941

 
3,821

Deferred debits and other assets
 
 
 
Regulatory assets
221

 
231

Goodwill
8

 
8

Prepaid pension asset
175

 
186

Other
82

 
6

Total deferred debits and other assets
486


431

Total assets
$
4,724


$
4,588


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

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)
September 30, 2019
 
December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
57

 
$
—

Long-term debt due within one year
91

 
91

Accounts payable
90

 
111

Accrued expenses
59

 
39

Payables to affiliates
26

 
33

Customer deposits
36

 
35

Regulatory liabilities
43

 
59

Other
33

 
7

Total current liabilities
435

 
375

Long-term debt
1,404

 
1,403

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
655

 
628

Non-pension postretirement benefits obligations
16

 
17

Regulatory liabilities
580

 
606

Other
114

 
50

Total deferred credits and other liabilities
1,365


1,301

Total liabilities
3,204


3,079

Commitments and contingencies

 

Shareholder's equity
 
 
 
Common stock
914

 
914

Retained earnings
606

 
595

Total shareholder's equity
1,520


1,509

Total liabilities and shareholder's equity
$
4,724


$
4,588


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

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
 
Nine Months Ended September 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

Net income
—

 
33

 
33

Common stock dividends
—

 
(35
)
 
(35
)
Balance, September 30, 2019
$
914

 
$
606

 
$
1,520


 
Nine Months Ended September 30, 2018
(In millions)
Common Stock
 
Retained Earnings
 
Total Shareholder's Equity
Balance, December 31, 2017
$
764

 
$
571

 
$
1,335

Net income
—

 
31

 
31

Common stock dividends
—

 
(36
)
 
(36
)
Balance, March 31, 2018
$
764

 
$
566

 
$
1,330

Net income
—

 
26

 
26

Common stock dividends
—

 
(4
)
 
(4
)
Contributions from parent
150

 
—

 
150

Balance, June 30, 2018
$
914

 
$
588

 
$
1,502

Net income
—

 
33

 
33

Common stock dividends
—

 
(18
)
 
(18
)
Balance, September 30, 2018
$
914

 
$
603

 
$
1,517



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


ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
(In millions)
2019
 
2018
 
2019
 
2018
Operating revenues
 
 
 
 
 
 
 
Electric operating revenues
$
417

 
$
406

 
$
964

 
$
983

Revenues from alternative revenue programs
1

 
(1
)
 
—

 
(4
)
Operating revenues from affiliates
1

 
1

 
2

 
2

Total operating revenues
419

 
406

 
966

 
981

Operating expenses
 
 
 
 
 
 
 
Purchased power
207

 
188

 
463

 
465

Purchased power from affiliates
3

 
10

 
16

 
21

Operating and maintenance
54

 
52

 
142

 
146

Operating and maintenance from affiliates
32

 
33

 
99

 
104

Depreciation and amortization
43

 
38

 
114

 
107

Taxes other than income
1

 
1

 
4

 
4

Total operating expenses
340

 
322

 
838

 
847

Operating income
79


84

 
128


134

Other income and (deductions)
 
 
 
 
 
 
 
Interest expense, net
(15
)
 
(16
)
 
(44
)
 
(48
)
Other, net
1

 
1

 
5

 
2

Total other income and (deductions)
(14
)
 
(15
)
 
(39
)
 
(46
)
Income before income taxes
65

 
69

 
89

 
88

Income taxes
2

 
8

 
2

 
12

Net income
$
63


$
61


$
87


$
76

Comprehensive income
$
63

 
$
61

 
$
87

 
$
76


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

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
 
Nine Months Ended
September 30,
(In millions)
2019

2018
Cash flows from operating activities
 
 
 
Net income
$
87

 
$
76

Adjustments to reconcile net income to net cash flows provided by operating activities:
 
 
 
Depreciation and amortization
114

 
107

Deferred income taxes and amortization of investment tax credits
2

 
24

Other non-cash operating activities
21

 
24

Changes in assets and liabilities:
 
 
 
Accounts receivable
(44
)
 
(66
)
Receivables from and payables to affiliates, net
(4
)
 
(3
)
Inventories
(4
)
 
(2
)
Accounts payable and accrued expenses
27

 
21

Income taxes
5

 
(3
)
Pension and non-pension postretirement benefit contributions
—

 
(6
)
Other assets and liabilities
(18
)
 
(12
)
Net cash flows provided by operating activities
186

 
160

Cash flows from investing activities
 
 
 
Capital expenditures
(300
)
 
(247
)
Other investing activities
—

 
(1
)
Net cash flows used in investing activities
(300
)
 
(248
)
Cash flows from financing activities
 
 
 
Changes in short-term borrowings
49

 
37

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

 
125

Repayments of short-term borrowings with maturities greater than 90 days
(125
)
 
—

Issuance of long-term debt
150

 
—

Retirement of long-term debt
(13
)
 
(22
)
Contributions from parent
155

 
—

Dividends paid on common stock
(100
)
 
(46
)
Other financing activities
(1
)
 
—

Net cash flows provided by financing activities
115

 
94

Increase in cash, cash equivalents and restricted cash
1

 
6

Cash, cash equivalents and restricted cash at beginning of period
30

 
31

Cash, cash equivalents and restricted cash at end of period
$
31


$
37

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


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)
September 30, 2019
 
December 31, 2018
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
13

 
$
7

Restricted cash and cash equivalents
3

 
4

Accounts receivable, net
 
 
 
Customer (net of allowance for uncollectible accounts of $15 and $18 as of September 30, 2019 and December 31, 2018, respectively)
142

 
95

Other (net of allowance for uncollectible accounts of $5 and $1 as of September 30, 2019 and December 31, 2018, respectively)
47

 
55

Receivables from affiliates
1

 
1

Inventories, net
37

 
33

Prepaid utility taxes
9

 
—

Regulatory assets
48

 
40

Other
7

 
5

Total current assets
307

 
240

Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,192 and $1,137 as of September 30, 2019 and December 31, 2018, respectively)
3,124

 
2,966

Deferred debits and other assets
 
 
 
Regulatory assets
370

 
386

Prepaid pension asset
56

 
67

Other
59

 
40

Total deferred debits and other assets
485

 
493

Total assets(a)
$
3,916

 
$
3,699


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

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

(In millions)
September 30, 2019
 
December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY
 
 
 
Current liabilities
 
 
 
Short-term borrowings
$
63

 
$
139

Long-term debt due within one year
19

 
18

Accounts payable
139

 
154

Accrued expenses
40

 
35

Payables to affiliates
24

 
28

Customer deposits
26

 
26

Regulatory liabilities
25

 
18

Other
11

 
4

Total current liabilities
347

 
422

Long-term debt
1,305

 
1,170

Deferred credits and other liabilities
 
 
 
Deferred income taxes and unamortized investment tax credits
569

 
535

Non-pension postretirement benefit obligations
18

 
17

Regulatory liabilities
365

 
402

Other
44

 
27

Total deferred credits and other liabilities
996

 
981

Total liabilities(a)
2,648

 
2,573

Commitments and contingencies

 

Shareholder's equity
 
 
 
Common stock
1,134

 
979

Retained earnings
134

 
147

Total shareholder's equity
1,268


1,126

Total liabilities and shareholder's equity
$
3,916


$
3,699

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

See the Combined Notes to Consolidated Financial Statements
55
Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
 
Nine Months Ended September 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

Net income
—

 
63

 
63

Common stock dividends
—

 
(76
)
 
(76
)
Balance, September 30, 2019
$
1,134

 
$
134

 
$
1,268


 
Nine Months Ended September 30, 2018
(In millions)
Common Stock
 
Retained Earnings
 
Total Shareholder's Equity
Balance, December 31, 2017
$
912

 
$
131

 
$
1,043

Net income
—

 
7

 
7

Common stock dividends
—

 
(9
)
 
(9
)
Balance, March 31, 2018
$
912

 
$
129

 
$
1,041

Net income
—

 
8

 
8

Common stock dividends
—

 
(10
)
 
(10
)
Balance, June 30, 2018
$
912


$
127

 
$
1,039

Net income
—

 
61

 
61

Common stock dividends
—

 
(27
)
 
(27
)
Balance, September 30, 2018
$
912

 
$
161

 
$
1,073



See the Combined Notes to Consolidated Financial Statements
56
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)

Note 1 — Significant Accounting Policies


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 September 30, 2019 and 2018 and for the three and nine months then ended are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2018 Consolidated Balance Sheets were derived from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for

57
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)

Note 1 — Significant Accounting Policies

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

58
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)

Note 1 — Significant Accounting Policies

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

59
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 2 — Variable Interest Entities


 
September 30, 2019
 
December 31, 2018
 
Exelon

Generation

PHI (a)
 
ACE
 
Exelon
 
Generation
 
PHI (a)
 
ACE
Cash and cash equivalents
$
168

 
$
168

 
$
—

 
$
—

 
$
414

 
$
414

 
$
—

 
$
—

Restricted cash and cash equivalents
76

 
73

 
3

 
3

 
66

 
62

 
4

 
4

Accounts receivable, net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Customer
163

 
163

 
—

 
—

 
146

 
146

 
—

 
—

Other
43

 
43

 
—

 
—

 
23

 
23

 
—

 
—

Unamortized energy contract asset (b)
23

 
23

 
—

 
—

 
25

 
25

 
—

 
—

Inventory, net
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Materials and supplies
222

 
222

 
—

 
—

 
212

 
212

 
—

 
—

Other current assets
50

 
48

 
2

 
—

 
52

 
49

 
3

 
—

Total current assets
745


740


5

 
3

 
938


931


7

 
4

Property, plant and equipment, net (c)
6,079

 
6,079

 
—

 
—

 
6,188

 
6,188

 
—

 
—

NDT funds
2,636

 
2,636

 
—

 
—

 
2,351

 
2,351

 
—

 
—

Unamortized energy contract asset (b)
258

 
258

 
—

 
—

 
274

 
274

 
—

 
—

Other noncurrent assets
69

 
52

 
17

 
15

 
258

 
232

 
26

 
19

Total noncurrent assets
9,042


9,025


17

 
15

 
9,071


9,045


26

 
19

Total assets
$
9,787


$
9,765


$
22

 
$
18

 
$
10,009


$
9,976


$
33

 
$
23

Long-term debt due within one year
$
556

 
$
535

 
$
21

 
$
19

 
$
87

 
$
66

 
$
21

 
$
18

Accounts payable
148

 
148

 
—

 
—

 
96

 
96

 
—

 
—

Accrued expenses
58

 
57

 
1

 
1

 
73

 
72

 
1

 
1

Unamortized energy contract liabilities
10

 
10

 
—

 
—

 
15

 
15

 
—

 
—

Other current liabilities
30

 
30

 
—

 
—

 
3

 
3

 
—

 
—

Total current liabilities
802

 
780

 
22

 
20

 
274

 
252

 
22

 
19

Long-term debt
532

 
504

 
28

 
26

 
1,072

 
1,025

 
47

 
40

Asset retirement obligations (d)
2,103

 
2,103

 
—

 
—

 
2,165

 
2,165

 
—

 
—

Unamortized energy contract liabilities
1

 
1

 
—

 
—

 
1

 
1

 
—

 
—

Other noncurrent liabilities
84

 
84

 
—

 
—

 
42

 
42

 
—

 
—

Total noncurrent liabilities
2,720

 
2,692

 
28

 
26

 
3,280

 
3,233

 
47

 
40

Total liabilities
$
3,522

 
$
3,472

 
$
50

 
$
46

 
$
3,554

 
$
3,485

 
$
69

 
$
59

_________
(a)
Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
(b)
These are unrestricted assets to Exelon and Generation.
(c)
Exelon’s and Generation’s balances include unrestricted assets of $41 million and $43 million as of September 30, 2019 and December 31, 2018, respectively.
(d)
Exelon’s and Generation’s balances include liabilities with recourse of $5 million as of September 30, 2019 and December 31, 2018.

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

Note 2 — Variable Interest Entities


As of September 30, 2019 and December 31, 2018, 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 the Nuclear Operating Services Agreement (NOSA) described further below.
Generation conducts the operational activities.
EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. See additional discussion below.
Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.
Generation conducts the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by EGRP. Generation is a minority interest holder.
Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.
Generation conducts the operational activities.
Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&E through a PPA.
The PPA contract absorbs variability through a performance guarantee.
Generation conducts all activities.
Equity investment in distributed energy company - Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE (see Unconsolidated VIEs disclosure below).

Generation fully impaired this investment in the third quarter of 2019. See Note 7— Asset Impairments for additional information.
Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.
Generation conducts the operational activities.
CENG - On April 1, 2014, Generation, CENG, and 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.
Exelon and Generation, where indicated, provide the following support to CENG:
•
Generation provided a $400 million loan to CENG. The loan balance was fully repaid by CENG in January 2019.
•
Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. See Note 22 — Commitments and Contingencies of the Exelon 2018 Form 10-K for additional information.
•
Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance.
•
Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.
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.

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

Note 2 — Variable Interest Entities


In 2017, Generation’s interests in EGRP were contributed to and are pledged for the EGR IV non-recourse debt project financing structure. Refer to Note 11— Debt and Credit Agreements for additional information.
As of September 30, 2019 and December 31, 2018, 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 Transition Funding - A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds. Proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees.
ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ACETF. The bondholders also have a variable interest for the investment made to purchase 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 September 30, 2019 and December 31, 2018, 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.
The following table presents summary information about Exelon's and Generation’s unconsolidated VIE entities:
 
September 30, 2019
 
December 31, 2018
 
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 
Total
 
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 
Total
Total assets(a)
$
614

 
$
453

 
$
1,067

 
$
597

 
$
472

 
$
1,069

Total liabilities(a)
36

 
224

 
260

 
37

 
222

 
259

Exelon's ownership interest in VIE(a)
—

 
201

 
201

 
—

 
223

 
223

Other ownership interests in VIE(a)
587

 
28

 
615

 
560

 
27

 
587

Registrants’ maximum exposure to loss:
 
 
 
 

 
 
 
 
 


Carrying amount of equity method investments
—

 
12

 
12

 
—

 
223

 
223

_________
(a)
These items represent amounts in the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
For each of the unconsolidated VIEs, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.

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

Note 2 — Variable Interest Entities


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

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

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

3. Mergers, Acquisitions and Dispositions (Exelon and Generation)
Acquisition of Handley Generating Station
On November 7, 2017, ExGen Texas Power, LLC (EGTP), and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware, which resulted in Exelon and Generation deconsolidating EGTP's assets and liabilities from their consolidated financial statements. Concurrently with the Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP's generating plants, the Handley Generating Station, which closed on April 4, 2018 for a purchase price of $62 million.
Disposition of Oyster Creek
On July 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and a private letter ruling from the IRS, which were satisfied in the second quarter 2019. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter, which was immaterial.
Under the terms of the transaction, Generation transferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events.
As a result of the transaction, in the third quarter of 2018, Exelon and Generation reclassified certain Oyster Creek assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. Exelon and Generation had $897 million and $777 million of Assets and Liabilities held for sale, respectively, at December 31, 2018. Upon remeasurement of the Oyster Creek ARO, Exelon and Generation recognized an $84 million and a $9 million pre-tax charge to Operating and maintenance expense in the third quarter of 2018 and in the second quarter of 2019, respectively. See Note 13 — Nuclear Decommissioning for additional information.

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

Note 3 — Mergers, Acquisitions and Dispositions

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

 
$
283

 
$
35

 
$
35

Consideration received or due
 
(146
)
 
(146
)
 
179

 
465

Revenues recognized
 
50

 
50

 
(187
)
 
(458
)
Balance at December 31, 2018
 
187

 
187

 
27

 
42

Consideration received or due
 
(109
)
 
(109
)
 
65

 
198

Revenues recognized
 
92

 
92

 
(66
)
 
(192
)
Balance at September 30, 2019
 
170

 
170

 
26

 
48


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

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

Note 4 — Revenue from Contracts with Customers

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

 
341

 
142

 
74

 
244

 
957

Generation
215

 
442

 
197

 
89

 
244

 
1,187


Revenue Disaggregation (All Registrants)
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 18 — Segment Information for the presentation of the Registrant's revenue disaggregation.
5. Leases (All Registrants)
Lessee
The Registrants have operating leases for which they are the lessees. The following tables outline the significant types of operating leases at each registrant and other terms and conditions of the lease agreements. The Registrants do not have material finance leases.
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Contracted generation
●
 
●
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real estate
●
 
●
 
●
 
●
 
●
 
●
 
●
 
●
 
●
Vehicles and equipment
●
 
●
 
●
 
●
 
●
 
●
 
●
 
●
 
●
(in years)
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Remaining lease terms
1-87
 
1-37
 
1-6
 
1-15
 
1-87
 
1-13
 
1-13
 
1-13
 
1-8
Options to extend the term
3-30
 
3-30
 
5
 
N/A
 
N/A
 
3-30
 
5
 
3-30
 
N/A
Options to terminate within
2-14
 
2
 
4
 
N/A
 
3
 
N/A
 
N/A
 
N/A
 
N/A
The components of lease costs for the three months ended September 30, 2019 were as follows:
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Operating lease costs
$
97

 
$
73

 
$
1

 
$
—

 
$
8

 
$
12

 
$
3

 
$
3

 
$
2

Variable lease costs
79

 
74

 
—

 
—

 
1

 
1

 
—

 
—

 
—

Short-term lease costs
5

 
5

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total lease costs (a)
$
181

 
$
152

 
$
1

 
$
—

 
$
9

 
$
13

 
$
3

 
$
3

 
$
2

__________
(a)
Excludes $29 million, $28 million, $1 million and $1 million of sublease income recorded at Exelon, Generation, PHI and DPL, respectively

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

Note 5 — Leases

The components of lease costs for the nine months ended September 30, 2019 were as follows:
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Operating lease costs
$
252

 
$
180

 
$
2

 
$
1

 
$
25

 
$
35

 
$
9

 
$
10

 
$
5

Variable lease costs
229

 
214

 
1

 
—

 
1

 
5

 
2

 
2

 
1

Short-term lease costs
16

 
16

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total lease costs (a)
$
497

 
$
410

 
$
3

 
$
1

 
$
26

 
$
40

 
$
11

 
$
12

 
$
6

__________
(a)
Excludes $48 million, $42 million, $6 million and $6 million of sublease income recorded at Exelon, Generation, PHI and DPL, respectively.
The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets as of September 30, 2019:
 
Exelon(a)
 
Generation(a)
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Operating lease ROU assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other deferred debits and other assets
$
1,374

 
$
926

 
$
10

 
$
2

 
$
83

 
$
304

 
$
66

 
$
75

 
$
24

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating lease liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other current liabilities
242

 
170

 
3

 
—

 
32

 
35

 
8

 
11

 
5

Other deferred credits and other liabilities
1,355

 
949

 
8

 
1

 
50

 
279

 
60

 
74

 
19

Total operating lease liabilities
$
1,597

 
$
1,119

 
$
11

 
$
1

 
$
82

 
$
314

 
$
68

 
$
85

 
$
24

__________
(a)
Exelon's and Generation's operating ROU assets and lease liabilities include $542 million and $703 million, respectively, related to contracted generation.
The weighted average remaining lease terms, in years, and discount rates for operating leases as of September 30, 2019 were as follows:
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Remaining lease term
10.1

 
10.6

 
4.7

 
4.3

 
5.6

 
9.0

 
9.6

 
9.5

 
5.3

Discount rate
4.5
%
 
4.8
%
 
3.1
%
 
3.3
%
 
3.6
%
 
4.0
%
 
3.7
%
 
3.7
%
 
3.3
%

Future minimum lease payments for operating leases as of September 30, 2019 were as follows:
Year
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
2019
$
65

 
$
50

 
$
1

 
$
—

 
$
1

 
$
11

 
$
3

 
$
2

 
$
2

2020
289

 
203

 
3

 
1

 
34

 
45

 
10

 
13

 
5

2021
246

 
162

 
3

 
—

 
31

 
43

 
9

 
12

 
5

2022
179

 
113

 
2

 
—

 
16

 
42

 
9

 
12

 
4

2023
148

 
100

 
1

 
—

 
—

 
41

 
8

 
11

 
4

Remaining years
1,123

 
837

 
2

 
—

 
19

 
197

 
43

 
53

 
6

Total
2,050

 
1,465

 
12

 
1

 
101

 
379

 
82

 
103

 
26

Interest
453

 
346

 
1

 
—

 
19

 
65

 
14

 
18

 
2

Total operating lease liabilities
$
1,597

 
$
1,119

 
$
11

 
$
1

 
$
82

 
$
314

 
$
68

 
$
85

 
$
24



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

Note 5 — Leases

Future minimum lease payments for operating leases under the prior lease accounting guidance as of December 31, 2018 were as follows:
Year
Exelon(a)(b)
 
Generation(a)(b)
 
ComEd(a)(c)
 
PECO(a)(c)
 
BGE(a)(c)(d)(e)
 
PHI(a)
 
Pepco(a)
 
DPL(a)(c)
 
ACE(a)
2019
$
140

 
$
33

 
$
7

 
$
5

 
$
35

 
$
48

 
$
11

 
$
14

 
$
7

2020
149

 
46

 
5

 
5

 
35

 
46

 
10

 
13

 
6

2021
143

 
46

 
4

 
5

 
33

 
43

 
9

 
12

 
5

2022
126

 
47

 
4

 
5

 
18

 
42

 
8

 
12

 
5

2023
97

 
46

 
3

 
5

 
3

 
39

 
8

 
10

 
4

Remaining years
723

 
545

 
—

 
—

 
19

 
159

 
40

 
35

 
5

Total minimum future lease payments
$
1,378

 
$
763

 
$
23

 
$
25

 
$
143

 
$
377

 
$
86

 
$
96

 
$
32

__________
(a)
Includes amounts related to shared use land arrangements.
(b)
Excludes Generation’s contingent operating lease payments associated with contracted generation.
(c)
Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd's, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectively. Also includes amounts related to shared use land arrangements.
(d)
Includes all future lease payments on a 99-year real estate lease that expires in 2106.
(e)
The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022, respectively.
Cash paid for amounts included in the measurement of lease liabilities for the nine months ended September 30, 2019 were as follows:
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Operating cash flows from operating leases
$
225

 
$
156

 
$
2

 
$
—

 
$
32

 
$
29

 
$
7

 
$
6

 
$
4


ROU assets obtained in exchange for lease obligations for the nine months ended September 30, 2019 were as follows:
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Operating leases
$
70

 
$
11

 
$
6

 
$
—

 
$
1

 
$
20

 
$
7

 
$
9

 
$
4


Lessor
The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and other terms and conditions of their lease agreements.
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Contracted generation
●
 
●
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Real estate
●
 
●
 
●
 
●
 
●
 
●
 
●
 
●
 
●
(in years)
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Remaining lease terms
1-84
 
1-33
 
1-18
 
1-84
 
24
 
1-14
 
2-7
 
13-14
 
1-3
Options to extend the term
1-79
 
1-5
 
5-79
 
5-50
 
N/A
 
5
 
N/A
 
N/A
 
N/A

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

Note 5 — Leases

The components of lease income for the three months ended September 30, 2019 were as follows:
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Operating lease income
$
30

 
$
29

 
$
—

 
$
—

 
$
—

 
$
1

 
$
—

 
$
1

 
$
—

Variable lease income
80

 
80

 
—

 
—

 
—

 
—

 
—

 
—

 
—


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

 
$
44

 
$
—

 
$
—

 
$
—

 
$
3

 
$
—

 
$
3

 
$
—

Variable lease income
209

 
206

 
—

 
—

 
—

 
3

 
—

 
3

 
—


Future minimum lease payments to be recovered under operating leases as of September 30, 2019 were as follows:
Year
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
2019
$
4

 
$
3

 
$
—

 
$
—

 
$
—

 
$
1

 
$
—

 
$
1

 
$
—

2020
51

 
46

 
—

 
—

 
—

 
4

 
—

 
3

 
—

2021
50

 
45

 
—

 
—

 
—

 
4

 
1

 
3

 
—

2022
50

 
45

 
—

 
—

 
—

 
5

 
—

 
4

 
—

2023
49

 
45

 
—

 
—

 
—

 
4

 
—

 
3

 
—

Remaining years
314

 
271

 
1

 
3

 
1

 
38

 
—

 
38

 
—

Total
$
518

 
$
455

 
$
1

 
$
3

 
$
1

 
$
56

 
$
1

 
$
52

 
$
—



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

Note 6 — Regulatory Matters

6. Regulatory Matters (All Registrants)
As discussed in Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The following discusses developments in 2019 and updates to the 2018 Form 10-K.
Utility Regulatory Matters (Exelon and the Utility Registrants)
Distribution Base Rate Case Proceedings
The following tables show the completed and pending distribution base rate case proceedings in 2019.
Completed Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Requested Revenue Requirement (Decrease) Increase
 
Approved Revenue Requirement (Decrease) Increase
 
Approved ROE
 
Approval Date
Rate Effective Date
ComEd - Illinois (Electric)
April 16, 2018
$
(23
)
 
$
(24
)
 
8.69%

December 4, 2018
January 1, 2019
PECO - Pennsylvania (Electric)
March 29, 2018
$
82

 
$
25

 
N/A
(a) 
December 20, 2018
January 1, 2019
BGE - Maryland (Natural Gas)
June 8, 2018 (amended October 12, 2018)
$
61

 
$
43

 
9.8%
 
January 4, 2019
January 4, 2019
ACE - New Jersey (Electric)
August 21, 2018 (amended November 19, 2018)
$
122

(b) 
$
70

(b) 
9.6%
 
March 13, 2019
April 1, 2019
Pepco - Maryland (Electric)
January 15, 2019 (amended May 16, 2019)
$
27

 
$
10

 
9.6%
 
August 12, 2019
August 13, 2019
__________
(a)
The PECO rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.
(b)
Requested and approved increases are before New Jersey sales and use tax.

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

Note 6 — Regulatory Matters

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 8, 2019
$
(6
)
8.91
%
December 2019
BGE - Maryland (Electric)(b)
May 24, 2019 (amended October 4, 2019)
$
74

10.3
%
December 2019
BGE - Maryland (Natural Gas)(b)
May 24, 2019 (amended October 4, 2019)
$
59

10.3
%
December 2019
Pepco - District of Columbia (Electric)(c)
May 30, 2019 (amended September 16, 2019)
$
160

10.3
%
Fourth quarter of 2020
__________
(a)
Reflects an increase of $57 million for the initial revenue requirement for 2019 and a decrease of $63 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.53%. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on ComEd's distribution formula rate filings.
(b)
On October 25, 2019, BGE filed a settlement agreement with the MDPSC. The settlement provides for an increase to BGE’s annual electric and natural gas distribution rates of $18 million and $45 million, respectively.
(c)
Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $84 million, $40 million and $36 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.
Transmission Formula Rates
Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation).
For 2019, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:
Registrant(a)
Initial Revenue Requirement Increase (Decrease)
Annual Reconciliation (Decrease) Increase
Total Revenue Requirement Increase (Decrease)
 
Allowed Return on Rate Base(c)
Allowed ROE(d)
ComEd
$
21

$
(16
)
$
5

 
8.21
%
11.50
%
BGE
(10
)
(23
)
(19
)
(b) 
7.35
%
10.50
%
Pepco
15

11

26


7.75
%
10.50
%
DPL
17

(1
)
16


7.14
%
10.50
%
ACE
11

(2
)
9


7.79
%
10.50
%
__________
(a)
All rates are effective June 2019, subject to review by the FERC and other parties, which is due by the fourth quarter of 2019.
(b)
The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $14 million to recover the costs of providing transmission service to specifically designated load by BGE.
(c)
Represents the weighted average debt and equity return on transmission rate bases.
(d)
As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped

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Note 6 — Regulatory Matters

at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.
Pending Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. PECO’s initial formula rate filing included a requested increase of  $22 million to PECO’s annual transmission revenue requirement, which reflected a ROE of  11%, inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures.
Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.
On July 22, 2019, PECO and other parties filed with FERC a settlement agreement, which includes a ROE of 10.35%, inclusive of a 50 basis point adder for being a member of a RTO. The settlement did not have a material impact on PECO’s 2017, 2018, or 2019 annual transmission revenue requirements. A final order from FERC is expected before the end of the first quarter of 2020. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.
Other State Regulatory Matters
Energy Efficiency Formula Rate. ComEd filed its annual energy efficiency formula rate update with the ICC on May 23, 2019. The filing establishes the revenue requirement used to set the rates that will take effect in January 2020 after the ICC’s review and approval. The revenue requirement requested is based on a reconciliation of the 2018 actual costs plus projected 2019 and 2020 expenditures.
Registrant
Initial Revenue Requirement Increase (Decrease)
Annual Reconciliation Increase (Decrease)
Total Revenue Requirement Increase (Decrease)
 
Requested Return on Rate Base
Requested ROE
ComEd
$
53

$
(2
)
$
51

(a) 
6.53
%
8.91
%
__________
(a)
The requested revenue requirement increase provides for a weighted average debt and equity return on rate base of 6.53% inclusive of an allowed ROE of 8.91%. The ROE reflects the average rate on 30-year treasury notes plus 580 basis points. The ROE applicable to the 2018 reconciliation year is 10.91% and the return on rate base is 7.49%, which include the Performance Adjustment, which can either increase or decrease the ROE by up to a maximum of 200 basis points.
Maryland Regulatory Matters
Maryland Alternative Rate Plans Rulemaking (Exelon, BGE, PHI, Pepco and DPL). On August 9, 2019, the MDPSC issued an order in which the MDPSC determined that it is now appropriate to move forward to implement alternative rate plans in Maryland. The MDPSC found that a multi-year rate plan, based on a historic test year and allowing up to three future test years, can produce just and reasonable rates. A working group has been convened to develop and submit a detailed implementation report to the MDPSC by December 20, 2019. The MDPSC will issue another order on next steps by January 30, 2020. BGE, Pepco and DPL cannot predict the outcome or the potential financial impact, if any, on BGE, Pepco or DPL.
New Jersey Regulatory Matters
ACE Infrastructure Investment Program Filing (Exelon, PHI and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s Infrastructure Investment Program (IIP) proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP allowed for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows

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

Note 6 — Regulatory Matters

for a recovery totaling $96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement.
New Jersey Clean Energy Legislation (Exelon, PHI and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Electric distribution utilities in New Jersey, including ACE, began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the utility’s procurement of the ZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information.
Other Federal Regulatory Matters
Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. As a result of the FERC’s order, ComEd, BGE, Pepco, DPL and ACE took a charge to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017 reducing their associated transmission-related income tax regulatory assets for the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula. See above for additional information regarding PECO's transmission formula rate filing.
On December 18, 2017, BGE filed for clarification and rehearing of FERC’s November 16, 2017 order and on February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.
On September 7, 2018, FERC issued orders rejecting BGE’s December 18, 2017 request for rehearing and clarification and ComEd's, Pepco's, DPL's and ACE's February 23, 2018 (as amended on July 9, 2018) filings, citing the lack of timeliness of the requests to recover amounts that would have been previously amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement, consistent with its November 16, 2017 order.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and refund TCJA transmission-related income tax regulatory liabilities for the prospective period starting on October 1, 2018. In addition, on October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order. On November 2, 2018, BGE filed an appeal of FERC’s September 7, 2018 order to the Court of Appeals for the D.C. Circuit. On April 26, 2019, FERC issued an order accepting ComEd’s, BGE’s, Pepco’s, DPL’s, and ACE’s October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. ComEd, BGE, Pepco, DPL, and ACE cannot predict the outcome of these proceedings.
If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be up to approximately $80 million, $52 million, $16 million, $12 million, $4 million, $6 million and $2 million, respectively, as of September 30, 2019.
Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2018, unless noted below. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on the specific regulatory assets and liabilities.

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

Note 6 — Regulatory Matters

ComEd. Regulatory assets increased $122 million primarily due to an increase of $186 million in Energy Efficiency Costs and $32 million Renewable Energy partially offset by a decrease of $97 million in Electric Distribution Formula Rate Annual Reconciliations.
PECO. Regulatory assets increased $62 million primarily due to an increase of $95 million in Deferred Income Taxes offset by a $34 million decrease in Electric Energy and Natural Gas Costs.
BGE. Regulatory liabilities decreased $90 million primarily due to a decrease of $40 million in Deferred Income Taxes and $43 million in Removal Costs.
Pepco. Regulatory assets decreased $84 million primarily due to a decrease of $39 million in Electric Energy and Natural Gas Costs, $26 million in DC PLUG charge and $14 million in AMI Programs - Deployment Costs and Legacy Meters. Regulatory liabilities decreased by $71 million primarily due to a decrease of $73 million in Deferred Income Taxes.
DPL. Regulatory liabilities decreased $42 million primarily due to a decrease of $29 million in Deferred Income Taxes and $10 million in Electric Energy and Natural Gas Costs.
ACE. Regulatory liabilities decreased $30 million primarily due to a decrease of $32 million in Deferred Income Taxes.
Capitalized Ratemaking Amounts Not Recognized (Exelon and the Utility Registrants)
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.
 
Exelon
 
ComEd(a)
 
PECO
 
BGE(b)
 
PHI
 
Pepco(c)
 
DPL(c)
 
ACE
September 30, 2019
$
59

 
$
4

 
$
—

 
$
47

 
$
8

 
$
5

 
$
3

 
$
—

December 31, 2018
$
65

 
$
8

 
$
—

 
$
49

 
$
8

 
$
5

 
$
3

 
$
—

_________
(a)
Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.
(b)
BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.
(c)
Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.
Generation Regulatory Matters (Exelon and Generation)
Illinois Regulatory Matters
Zero Emission Standard. Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. During the first quarter of 2018, Generation recognized $150 million of revenue related to ZECs generated from June 1, 2017 through December 31, 2017.
On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. Both lawsuits argued that the Illinois ZEC program would distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices and sought a permanent injunction preventing the implementation of the program. The lawsuits were dismissed by the district court on July 14, 2017. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. On January 7, 2019, plaintiffs filed a petition seeking U.S. Supreme Court review of the case, which was denied on April 15, 2019.

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

Note 6 — Regulatory Matters

New Jersey Regulatory Matters
New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that will provide compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs.
On November 19, 2018, NJBPU issued an order providing for the method and application process for determining the eligibility of nuclear power plants, a draft method and process for ranking and selecting eligible nuclear power plants, and the establishment of a mechanism for each regulated utility to purchase ZECs from selected nuclear power plants. On December 19, 2018, PSEG filed complete applications seeking NJBPU approval for Salem 1 and Salem 2, of which Generation owns a 42.59% ownership interest, to participate in the ZEC program. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $21 million and $31 million for the three and nine months ended September 30, 2019. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. The appeal does not prevent implementation of the ZEC program. Exelon and Generation cannot predict the outcome of the appeal. See Note 8 — Early Plant Retirements for additional information related to Salem.
New York Regulatory Matters
New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC.
On October 19, 2016, a coalition of fossil-generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically, that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors, which was dismissed by the district court on July 25, 2017. On September 27, 2018, the U.S. Court of Appeals for the Second Circuit affirmed the lower court's dismissal of the complaint against the ZEC program. On January 7, 2019, the fossil-generation companies filed a petition seeking U.S. Supreme Court review of the case which was denied on April 15, 2019.
In addition, on November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. Subsequently, Generation, CENG and the NYPSC filed motions to dismiss the state court action, which were later opposed by the plaintiffs. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. On October 8, 2019, the court dismissed all remaining claims. The petitioners have until November 11, 2019 to file a notice of appeal.
See Note 8 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.
Federal Regulatory Matters
Operating License Renewals
Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) 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 April 21, 2016, Generation and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a settlement agreement (DOI Settlement) resolving all fish passage issues between the parties.

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

Note 6 — Regulatory Matters


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

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

The financial impact of the DOI and MDE Settlements and other anticipated license commitments are estimated to be $11 million to $14 million per year, on average, recognized over the new license term, including capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license. As of September 30, 2019, $41 million of direct costs associated with Conowingo licensing efforts have been capitalized. Generation’s current depreciation provision for Conowingo assumes renewal of the FERC license.
7. 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.
Equity Method Investments in Certain Distributed Energy Companies
In the third quarter of 2019, Generation’s equity method investments in certain distributed energy companies were fully impaired due to an other-than-temporary decline in market conditions and underperforming projects. Exelon and Generation recorded a pre-tax impairment charge of $164 million in Equity in losses of unconsolidated affiliates and an offsetting pre-tax $96 million in Net income attributable to noncontrolling interests in their Consolidated Statements of Operations and Comprehensive Income. As a result, Generation accelerated the amortization of investment tax credits associated with these companies and Exelon and Generation recorded a benefit of $46 million in Income taxes. The impairment charge and the accelerated amortization of investment tax credits resulted in a net $15 million decrease to Exelon’s and Generation’s earnings. See Note 2 — Variable Interest Entities for additional information.

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

Note 7 — Asset Impairments

Antelope Valley Solar Facility
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of September 30, 2019, Generation had approximately $730 million of net long-lived assets related to Antelope Valley. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and no impairment charge was recorded. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley’s net long-lived assets, which could be material.
Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,930 million of additional net long-lived assets as of September 30, 2019. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling interests. To date, there have been no indicators to suggest that the carrying amount of other net long-lived assets of EGR IV may not be recoverable.
Generation will continue to monitor the bankruptcy proceedings for any changes in circumstances that may indicate the carrying amount of the net long-lived assets of Antelope Valley or other long-lived assets of EGR IV may not be recoverable.
See Note 11 - Debt and Credit Agreements for additional information on the PG&E bankruptcy.
8. Early Plant Retirements (Exelon and Generation)
Exelon and Generation continuously evaluate factors that affect the current and expected economic value of Generation’s plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in 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. See Note 6 — Regulatory Matters for additional information on the Illinois ZES, New Jersey ZEC program and New York CES.
In Pennsylvania, the TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Generation announced that it would permanently cease generation operations at TMI. On September 20, 2019, Generation permanently ceased generation operations at TMI.

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

Note 8 — Early Plant Retirements

On February 2, 2018, Generation announced that it would permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current operating cycle and permanently ceased generation operations on September 17, 2018.
As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel, as well as operating and maintenance expenses. See Note 13 — Nuclear Decommissioning for additional information on changes to the nuclear decommissioning ARO balance. The total impact for the three and nine months ended September 30, 2019 and 2018 are summarized in the table below.
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
Income statement expense (pre-tax)
 
2019
 
2018
 
2019
 
2018
Depreciation and amortization(a)
 
 
 
 
 
 
 
 
Accelerated depreciation
 
$
71

 
$
152

 
$
216

 
$
441

Accelerated nuclear fuel amortization
 
3

 
18

 
13

 
52

Operating and maintenance(b)
 
39

 
4

 
(44
)
 
32

Total
 
$
113

 
$
174

 
$
185

 
$
525

_________
(a)
Reflects incremental accelerated depreciation and amortization for TMI for the three and nine months ended September 30, 2019. Reflects incremental accelerated depreciation for TMI and Oyster Creek for the three and nine months ended September 30, 2018. The Oyster Creek amounts are from February 2, 2018 through September 17, 2018. The TMI amounts are through September 20, 2019.
(b)
In 2019, primarily reflects the net impacts associated with the remeasurements of the TMI ARO in the first and third quarters. See Note 13 — Nuclear Decommissioning for additional information on the first quarter 2019 TMI ARO update. In 2018, primarily reflects materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments associated with the early retirement decisions for TMI and Oyster Creek. Excludes the charges in the third quarter of 2018 and second quarter of 2019 to Operating and maintenance expense for the ARO remeasurement due to the sale of Oyster Creek. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.
Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.
Other Generation
On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets absent regulatory reforms on June 1, 2022, at the end of the then-current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 was then committed through May 2021.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. Those adjustments were reflected in a compliance filing filed March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. Initial briefs in the ROE proceeding were filed on April 19, 2019 and reply briefs were filed on July 18, 2019. On January 4, 2019, Generation notified ISO-NE that it will participate in the Forward Capacity Market auction for the 2022 - 2023 capacity commitment period. In addition, on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 order, which does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022-2023 capacity commitment period. On June 10, 2019, ISO-NE announced that it has determined that Mystic 8 and 9 are needed for fuel security for the 2023-2024 capacity commitment period.

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

Note 8 — Early Plant Retirements

On March 25, 2019, ISO-NE filed the Inventoried Energy Program, which is intended to provide an interim fuel security program pending conclusion of the stakeholder process to develop a long-term, market-based solution to address fuel security. Exelon filed comments on the Inventoried Energy Program proposal on April 15, 2019. On May 8, 2019, FERC issued a deficiency letter to ISO-NE seeking additional information on the Inventoried Energy Program proposal, and ISO-NE filed a response on June 6, 2019. On August 5, 2019, FERC allowed the Inventoried Energy Program to take effect by operation of law. Several parties have filed requests for rehearing. FERC ordered ISO-NE to file long-term, market-based fuel security rules by October 15, 2019. On August 30, 2019, FERC granted an extension of time to file the long-term, market-based fuel security rules to April 15, 2020.
The following table provides the balance sheet amounts as of September 30, 2019 for Exelon's and Generation’s significant assets and liabilities associated with the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by the failure to adopt long-term solutions for reliability and fuel security.
 
 
September 30, 2019
Asset Balances
 
 
Materials and supplies inventory
 
$
31

Fuel inventory
 
5

Completed plant, net
 
889

Construction work in progress
 
7

Liability Balances
 
 
Asset retirement obligation
 
(2
)

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

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

Note 9 — Fair Value of Financial Assets and Liabilities

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

Exelon
 
$
36,304

 
$
38,056

 
$
2,541

 
$
40,597

 
$
35,424

 
$
33,711

 
$
2,158

 
$
35,869

Generation
 
8,613

 
7,962

 
1,398

 
9,360

 
8,793

 
7,467

 
1,443

 
8,910

ComEd
 
8,196

 
9,622

 
—

 
9,622

 
8,101

 
8,390

 
—

 
8,390

PECO
 
3,404

 
3,891

 
50

 
3,941

 
3,084

 
3,157

 
50

 
3,207

BGE
 
3,270

 
3,678

 
—

 
3,678

 
2,876

 
2,950

 
—

 
2,950

PHI
 
6,494

 
5,993

 
1,093

 
7,086

 
6,259

 
5,436

 
665

 
6,101

Pepco
 
2,860

 
3,249

 
395

 
3,644

 
2,719

 
2,901

 
196

 
3,097

DPL
 
1,495

 
1,437

 
232

 
1,669

 
1,494

 
1,303

 
193

 
1,496

ACE
 
1,324

 
1,034

 
466

 
1,500

 
1,188

 
987

 
275

 
1,262

Long-Term Debt to Financing Trusts(a)

Exelon
 
$
390

 
$
—

 
$
426

 
$
426

 
$
390

 
$
—

 
$
400

 
$
400

ComEd
 
205

 
—

 
223

 
223

 
205

 
—

 
209

 
209

PECO
 
184

 
—

 
203

 
203

 
184

 
—

 
191

 
191

SNF Obligation
Exelon
 
$
1,193

 
$
1,017

 
$
—

 
$
1,017

 
$
1,171

 
$
949

 
$
—

 
$
949

Generation
 
1,193

 
1,017

 
—

 
1,017

 
1,171

 
949

 
—

 
949

____
(a)
Includes unamortized debt issuance costs which are not fair valued.
Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2019 and December 31, 2018:
Exelon and Generation
 
Exelon
 
Generation
As of September 30, 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)
$
1,719

 
$
—

 
$
—

 
$
—

 
$
1,719

 
$
896

 
$
—

 
$
—

 
$
—

 
$
896

NDT fund investments
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 

Cash equivalents(b)
315

 
78

 
—

 
—

 
393

 
315

 
78

 
—

 
—

 
393

Equities
3,121

 
1,727

 
—


1,314

 
6,162

 
3,121

 
1,727

 
—


1,314

 
6,162

Fixed income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Corporate debt
—

 
1,473

 
259

 
—

 
1,732

 
—

 
1,473

 
259

 
—

 
1,732

U.S. Treasury and agencies
1,777

 
152

 
—

 
—

 
1,929

 
1,777

 
152

 
—

 
—

 
1,929

Foreign governments
—

 
56

 
—

 
—

 
56

 
—

 
56

 
—

 
—

 
56

State and municipal debt
—

 
85

 
—

 
—

 
85

 
—

 
85

 
—

 
—

 
85

Other(c)
—

 
23

 
—

 
979

 
1,002

 
—

 
23

 
—

 
979

 
1,002


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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 9 — Fair Value of Financial Assets and Liabilities

 
Exelon
 
Generation
As of September 30, 2019
Level 1
 
Level 2
 
Level 3
 
Not subject to leveling
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Not subject to leveling
 
Total
Fixed income subtotal
1,777


1,789


259

 
979


4,804


1,777


1,789


259

 
979


4,804

Middle market lending
—

 
—

 
255

 
445

 
700

 
—

 
—

 
255

 
445

 
700

Private equity
—

 
—

 
—

 
398

 
398

 
—

 
—

 
—

 
398

 
398

Real estate
—

 
—

 
—

 
581

 
581

 
—

 
—

 
—

 
581

 
581

NDT fund investments subtotal(d)
5,213


3,594


514

 
3,717


13,038


5,213


3,594


514

 
3,717


13,038

Rabbi trust investments
 
 
 
 
 
 
 
 

 
 
 
 
 
 
 
 
 

Cash equivalents
49

 
—

 
—

 
—

 
49

 
4

 
—

 
—

 
—

 
4

Mutual funds
77

 
—

 
—

 
—

 
77

 
24

 
—

 
—

 
—

 
24

Fixed income
—

 
13

 
—

 
—

 
13

 
—

 
—

 
—

 
—

 
—

Life insurance contracts
—

 
76

 
40

 
—

 
116

 
—

 
24

 
—

 
—

 
24

Rabbi trust investments subtotal
126


89


40

 
—


255


28


24


—

 
—


52

Commodity derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Economic hedges
533

 
1,488

 
1,817

 
—

 
3,838

 
533

 
1,488

 
1,817

 
—

 
3,838

Proprietary trading
—

 
54

 
156

 
—

 
210

 
—

 
54

 
156

 
—

 
210

Effect of netting and allocation of collateral(e)(f)
(677
)
 
(1,261
)
 
(1,025
)
 
—

 
(2,963
)
 
(677
)
 
(1,261
)
 
(1,025
)
 
—

 
(2,963
)
Commodity derivative assets subtotal
(144
)

281


948

 
—


1,085


(144
)

281


948

 
—


1,085

Total assets
6,914


3,964


1,502


3,717


16,097


5,993


3,899


1,462


3,717


15,071

Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity derivative liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Economic hedges
(773
)
 
(1,695
)
 
(1,686
)
 
—

 
(4,154
)
 
(773
)
 
(1,695
)
 
(1,406
)
 
—

 
(3,874
)
Proprietary trading
—

 
(59
)
 
(89
)
 
—

 
(148
)
 
—

 
(59
)
 
(89
)
 
—

 
(148
)
Effect of netting and allocation of collateral(e)(f)
770

 
1,585

 
1,329

 
—

 
3,684

 
770

 
1,585

 
1,329

 
—

 
3,684

Commodity derivative liabilities subtotal
(3
)
 
(169
)
 
(446
)
 
—

 
(618
)
 
(3
)
 
(169
)
 
(166
)
 
—

 
(338
)
Deferred compensation obligation
—

 
(140
)
 
—

 
—

 
(140
)
 
—

 
(37
)
 
—

 
—

 
(37
)
Total liabilities
(3
)

(309
)

(446
)
 
—


(758
)

(3
)

(206
)

(166
)
 
—


(375
)
Total net assets
$
6,911


$
3,655


$
1,056

 
$
3,717


$
15,339


$
5,990


$
3,693


$
1,296

 
$
3,717


$
14,696


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

Note 9 — Fair Value of Financial Assets and Liabilities

 
Exelon
 
Generation
As of December 31, 2018
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)
$
1,243

 
$
—

 
$
—

 
$
—

 
$
1,243

 
$
581

 
$
—

 
$
—

 
$
—

 
$
581

NDT fund investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


Cash equivalents(b)
252

 
86

 
—

 
—

 
338

 
252

 
86

 
—

 
—

 
338

Equities
2,918


1,591


—


1,381


5,890


2,918


1,591


—


1,381


5,890

Fixed income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Corporate debt
—

 
1,593

 
230

 
—

 
1,823

 
—

 
1,593

 
230

 
—

 
1,823

U.S. Treasury and agencies
2,081

 
99

 
—

 
—

 
2,180

 
2,081

 
99

 
—

 
—

 
2,180

Foreign governments
—

 
50

 
—

 
—

 
50

 
—

 
50

 
—

 
—

 
50

State and municipal debt
—

 
149

 
—

 
—

 
149

 
—

 
149

 
—

 
—

 
149

Other(c)
—

 
30

 
—

 
846

 
876

 
—

 
30

 
—

 
846

 
876

Fixed income subtotal
2,081


1,921


230

 
846


5,078


2,081


1,921


230

 
846


5,078

Middle market lending
—

 
—

 
313

 
367

 
680

 
—

 
—

 
313

 
367

 
680

Private equity
—

 
—

 
—

 
329

 
329

 
—

 
—

 
—

 
329

 
329

Real estate
—

 
—

 
—

 
510

 
510

 
—

 
—

 
—

 
510

 
510

NDT fund investments subtotal(d)
5,251


3,598


543

 
3,433


12,825


5,251


3,598


543

 
3,433

 
12,825

Rabbi trust investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
48

 
—

 
—

 
—

 
48

 
5

 
—

 
—

 
—

 
5

Mutual funds
72

 
—

 
—

 
—

 
72

 
24

 
—

 
—

 
—

 
24

Fixed income
—

 
15

 
—

 
—

 
15

 
—

 
—

 
—

 
—

 
—

Life insurance contracts
—

 
70

 
38

 
—

 
108

 
—

 
22

 
—

 
—

 
22

Rabbi trust investments subtotal
120


85


38

 
—


243


29


22


—

 
—


51

Commodity derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Economic hedges
541

 
2,760

 
1,470

 
—

 
4,771

 
541

 
2,760

 
1,470

 
—

 
4,771

Proprietary trading
—

 
69

 
77

 
—

 
146

 
—

 
69

 
77

 
—

 
146

Effect of netting and allocation of collateral(e)(f)
(582
)
 
(2,357
)
 
(732
)
 
—

 
(3,671
)
 
(582
)
 
(2,357
)
 
(732
)
 
—

 
(3,671
)
Commodity derivative assets subtotal
(41
)

472


815

 
—


1,246


(41
)

472


815

 
—


1,246

Total assets
6,573


4,155


1,396


3,433


15,557


5,820


4,092


1,358


3,433


14,703


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

Note 9 — Fair Value of Financial Assets and Liabilities

 
Exelon
 
Generation
As of December 31, 2018
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
(642
)
 
(2,963
)
 
(1,276
)
 
—

 
(4,881
)
 
(642
)
 
(2,963
)
 
(1,027
)
 
—

 
(4,632
)
Proprietary trading
—

 
(73
)
 
(21
)
 
—

 
(94
)
 
—

 
(73
)
 
(21
)
 
—

 
(94
)
Effect of netting and allocation of collateral(e)(f)
639

 
2,581

 
808

 
—

 
4,028

 
639

 
2,581

 
808

 
—

 
4,028

Commodity derivative liabilities subtotal
(3
)

(455
)

(489
)
 
—


(947
)

(3
)

(455
)

(240
)
 
—


(698
)
Deferred compensation obligation
—

 
(137
)
 
—

 
—

 
(137
)
 
—

 
(35
)
 
—

 
—

 
(35
)
Total liabilities
(3
)

(592
)

(489
)
 
—


(1,084
)

(3
)

(490
)

(240
)
 
—


(733
)
Total net assets
$
6,570


$
3,563


$
907

 
$
3,433


$
14,473


$
5,817


$
3,602


$
1,118

 
$
3,433


$
13,970

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

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

Note 9 — Fair Value of Financial Assets and Liabilities

For commingled funds and mutual funds, which are not publicly quoted, the fair value is primarily derived from the quoted prices in active markets on the underlying securities and can typically be redeemed monthly with 30 or less days of notice and without further restrictions. For managed middle market funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon’s understanding of the investment funds. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.
ComEd, PECO and BGE
 
ComEd
 
PECO
 
BGE
As of September 30, 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)
$
264

 
$
—

 
$
—

 
$
264

 
$
207

 
$
—

 
$
—

 
$
207

 
$
122

 
$
—

 
$
—

 
$
122

Rabbi trust investments
 
 
 
 
 
 

 
 
 
 
 
 
 

 
 
 
 
 
 
 

Mutual funds
—

 
—

 
—

 
—

 
8

 
—

 
—

 
8

 
7

 
—

 
—

 
7

Life insurance contracts
—

 
—

 
—

 
—

 
—

 
11

 
—

 
11

 
—

 
—

 
—

 
—

Rabbi trust investments subtotal
—


—


—


—


8


11


—


19


7


—


—


7

Total assets
264


—


—


264


215


11


—


226


129


—


—


129

Liabilities
 
 
 
 
 
 

 
 
 
 
 
 
 

 
 
 
 
 
 
 

Deferred compensation obligation
—

 
(7
)
 
—

 
(7
)
 
—

 
(8
)
 
—

 
(8
)
 
—

 
(5
)
 
—

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

 
—

 
(280
)
 
(280
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total liabilities
—

 
(7
)
 
(280
)
 
(287
)
 
—

 
(8
)
 
—

 
(8
)
 
—

 
(5
)
 
—

 
(5
)
Total net assets (liabilities)
$
264

 
$
(7
)
 
$
(280
)
 
$
(23
)
 
$
215

 
$
3

 
$
—

 
$
218

 
$
129

 
$
(5
)
 
$
—

 
$
124

 
ComEd
 
PECO
 
BGE
As of December 31, 2018
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)
$
209

 
$
—

 
$
—

 
$
209

 
$
111

 
$
—

 
$
—

 
$
111

 
$
4

 
$
—

 
$
—

 
$
4

Rabbi trust investments
 
 
 
 
 
 

 
 
 
 
 
 
 

 
 
 
 
 
 
 

Mutual funds
—

 
—

 
—

 
—

 
7

 
—

 
—

 
7

 
6

 
—

 
—

 
6

Life insurance contracts
—

 
—

 
—

 
—

 
—

 
10

 
—

 
10

 
—

 
—

 
—

 
—

Rabbi trust investments subtotal
—


—


—


—


7


10


—


17


6


—


—


6

Total assets
209


—


—


209


118


10


—


128


10


—


—


10

Liabilities
 
 
 
 
 
 

 
 
 
 
 
 
 

 
 
 
 
 
 
 

Deferred compensation obligation
—

 
(6
)
 
—

 
(6
)
 
—

 
(10
)
 
—

 
(10
)
 
—

 
(5
)
 
—

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

 
—

 
(249
)
 
(249
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total liabilities
—

 
(6
)
 
(249
)
 
(255
)
 
—

 
(10
)
 
—

 
(10
)
 
—

 
(5
)
 
—

 
(5
)
Total net assets (liabilities)
$
209

 
$
(6
)
 
$
(249
)
 
$
(46
)
 
$
118

 
$
—

 
$
—

 
$
118

 
$
10

 
$
(5
)
 
$
—

 
$
5


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

Note 9 — Fair Value of Financial Assets and Liabilities

_________
(a)
ComEd excludes cash of $76 million and $93 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $31 million and $28 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $171 million and $166 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  PECO excludes cash of $23 million and $24 million at September 30, 2019 and December 31, 2018, respectively.  BGE excludes cash of $8 million and $7 million at September 30, 2019 and December 31, 2018, respectively, and restricted cash of $1 million and $2 million at September 30, 2019 and December 31, 2018, respectively.
(b)
The Level 3 balance consists of the current and noncurrent liability of $27 million and $253 million, respectively, at September 30, 2019, and $26 million and $223 million, respectively, at December 31, 2018, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
PHI, Pepco, DPL and ACE
 
As of September 30, 2019
 
As of December 31, 2018
PHI
Level 1
 
Level 2
 
Level 3
 
Total
 
Level 1
 
Level 2
 
Level 3
 
Total
Assets
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents(a)
$
107

 
$
—

 
$
—

 
$
107

 
$
147

 
$
—

 
$
—

 
$
147

Rabbi trust investments
 
 
 
 
 
 

 
 
 
 
 
 
 

Cash equivalents
43

 
—

 
—

 
43

 
42

 
—

 
—

 
42

Mutual funds
13

 
—

 
—

 
13

 
13

 
—

 
—

 
13

Fixed income
—

 
13

 
—

 
13

 
—

 
15

 
—

 
15

Life insurance contracts
—

 
24

 
40

 
64

 
—

 
22

 
38

 
60

Rabbi trust investments subtotal
56


37


40


133


55


37


38


130

Total assets
163


37


40


240

 
202


37


38


277

Liabilities
 
 
 
 
 
 

 
 
 
 
 
 
 

Deferred compensation obligation
—

 
(19
)
 
—

 
(19
)
 
—

 
(21
)
 
—

 
(21
)
Total liabilities
—


(19
)

—


(19
)

—


(21
)

—


(21
)
Total net assets
$
163


$
18


$
40


$
221

 
$
202


$
16


$
38


$
256

 
Pepco
 
DPL
 
ACE
As of September 30, 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

 
$
—

 
$
—

 
$
—

 
$
—

 
$
18

 
$
—

 
$
—

 
$
18

Rabbi trust investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
43

 
—

 
—

 
43

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Fixed income
—

 
3

 
—

 
3

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Life insurance contracts
—

 
24

 
40

 
64

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Rabbi trust investments subtotal
43


27


40


110


—


—


—


—


—


—


—


—

Total assets
77


27


40


144


—


—


—


—


18


—


—


18

Liabilities

 

 

 


 

 

 

 

 

 

 

 

Deferred compensation obligation
—

 
(2
)
 
—

 
(2
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total liabilities
—


(2
)

—


(2
)

—


—


—


—


—


—


—


—

Total net assets
$
77

 
$
25

 
$
40

 
$
142

 
$
—

 
$
—

 
$
—

 
$
—

 
$
18

 
$
—

 
$
—

 
$
18


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

Note 9 — Fair Value of Financial Assets and Liabilities


Pepco
 
DPL
 
ACE
As of December 31, 2018
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)
$
38

 
$
—

 
$
—

 
$
38

 
$
16

 
$
—

 
$
—

 
$
16

 
$
23

 
$
—

 
$
—

 
$
23

Rabbi trust investments
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
41

 
—

 
—

 
41

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Fixed income
—

 
5

 
—

 
5

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Life insurance contracts
—

 
22

 
37

 
59

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Rabbi trust investments subtotal
41


27


37


105


—


—


—


—


—


—


—


—

Total assets
79


27


37


143


16


—


—


16


23


—


—


23

Liabilities
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Deferred compensation obligation
—

 
(3
)
 
—

 
(3
)
 
—

 
(1
)
 
—

 
(1
)
 
—

 
—

 
—

 
—

Total liabilities
—

 
(3
)
 
—

 
(3
)
 
—

 
(1
)
 
—

 
(1
)
 
—

 
—

 
—

 
—

Total net assets (liabilities)
$
79

 
$
24

 
$
37


$
140

 
$
16

 
$
(1
)
 
$
—

 
$
15

 
$
23

 
$
—

 
$
—

 
$
23

_________
(a)
PHI excludes cash of $45 million and $39 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $15 million and $19 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  Pepco excludes cash of $18 million and $15 million at September 30, 2019 and December 31, 2018, respectively. DPL excludes cash of $11 million and $8 million at September 30, 2019 and December 31, 2018, respectively. ACE excludes cash of $13 million and $7 million at September 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $15 million and $19 million at September 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2019 and 2018:
 
Exelon
 
Generation
 
ComEd
 
PHI and Pepco
 
 
Three Months Ended September 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 June 30, 2019
$
1,179

 
$
539

 
$
873

 
$
1,412

 
$
(273
)
 
$
40

 
$
—

Total realized / unrealized gains (losses)

 
 
 
 
 

 
 
 
 
 
 
Included in net income
(171
)
 
2

 
(173
)
(a) 
(171
)
 
—

 
—

 
—

Included in noncurrent payables to affiliates
—

 
11

 
—

 
11

 
—

 
—

 
(11
)
Included in regulatory assets/liabilities
4

 
—

 
—

 
—

 
(7
)
(b) 
—

 
11

Change in collateral
41

 
—

 
41

 
41

 
—

 
—

 
—

Purchases, sales, issuances and settlements


 
 
 
 
 

 
 
 
 
 
 
Purchases
53

 
1

 
52

 
53

 
—

 
—

 
—

Sales
(22
)
 
(21
)
 
(1
)
 
(22
)
 
—

 
—

 
—

Settlements
(18
)
 
(18
)
 
—

 
(18
)
 
—

 
—

 
—

Transfers into Level 3
1

 
—

 
1

(c) 
1

 
—

 
—

 
—

Transfers out of Level 3
(11
)
 
—

 
(11
)
(c) 
(11
)
 
—

 
—

 
—

Balance at September 30, 2019
$
1,056

 
$
514

 
$
782

 
$
1,296

 
$
(280
)
 
$
40

 
$
—

The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2019
$
(18
)
 
$
2

 
$
(20
)
 
$
(18
)
 
$
—

 
$
—

 
$
—


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

Note 9 — Fair Value of Financial Assets and Liabilities

 
Exelon
 
Generation
 
ComEd
 
PHI and Pepco
 
 
Nine Months Ended September 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
(125
)
 
5

 
(132
)
(a) 
(127
)
 
—

 
2

 
—

Included in noncurrent payables to affiliates
—

 
32

 
—

 
32

 
—

 
—

 
(32
)
Included in regulatory assets
1

 
—

 
—

 
—

 
(31
)
(b) 
—

 
32

Change in collateral
227

 
—

 
227

 
227

 
—

 
—

 
—

Purchases, sales, issuances and settlements


 
 
 
 
 


 
 
 
 
 
 
Purchases
163

 
43

 
120

 
163

 
—

 
—

 
—

Sales
(23
)
 
(21
)
 
(2
)
 
(23
)
 
—

 
—

 
—

Settlements
(88
)
 
(88
)
 
—

 
(88
)
 
—

 
—

 
—

Transfers into Level 3
5

 
—

 
5

(c) 
5

 
—

 
—

 
—

Transfers out of Level 3
(11
)
 
—

 
(11
)
(c) 
(11
)
 
—

 
—

 
—

Balance as of September 30, 2019
$
1,056

 
$
514

 
$
782

 
$
1,296

 
$
(280
)
 
$
40

 
$
—

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2019
$
173

 
$
5

 
$
166

 
$
171

 
$
—

 
$
2

 
$
—


__________
(a)
Includes a reduction for the reclassification of $153 million and $298 million of realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2019, respectively.
(b)
Includes $7 million of decreases in fair value and an increase for realized losses due to settlements of $4 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2019. Includes $31 million of decreases in fair value and an increase for realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2019.
(c)
Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.

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

Note 9 — Fair Value of Financial Assets and Liabilities

 
Exelon
 
Generation
 
ComEd
 
PHI and Pepco
 
 
Three Months Ended September 30, 2018
Total
 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 
Total Generation
 
Mark-to-Market
Derivatives
 
Life Insurance Contracts
 
Eliminated in Consolidation
Balance as of June 30, 2018
$
1,106

 
$
585

 
$
737

 
$
1,322

 
$
(252
)
 
$
36

 
$
—

Total realized / unrealized gains (losses)
 
 
 
 
 
 


 
 
 
 
 
 
Included in net income
(259
)
 
(1
)
 
(259
)
(a) 
(260
)
 
—

 
1

 
—

Included in noncurrent payables to affiliates
—

 
(4
)
 
—

 
(4
)
 
—

 
—

 
4

Included in regulatory assets
(11
)
 
—

 
—

 
—

 
(7
)
(b) 
—

 
(4
)
Change in collateral
(44
)
 
—

 
(44
)
 
(44
)
 
—

 
—

 
—

Purchases, sales, issuances and settlements

 
 
 
 
 


 
 
 
 
 
 
Purchases
96

 
15

 
81

 
96

 
—

 
—

 
—

Settlements
(29
)
 
(29
)
 
—

 
(29
)
 
—

 
—

 
—

Transfers into Level 3
3

 
—

 
3

(c) 
3

 
—

 
—

 
—

Transfers out of Level 3
(6
)
 
—

 
(6
)
(c) 
(6
)
 
—

 
—

 
—

Balance as of September 30, 2018
$
856

 
$
566


$
512


$
1,078


$
(259
)

$
37

 
$
—

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

 
$
—

 
$
—


 
Exelon
 
Generation
 
ComEd
 
PHI and Pepco
 
 
Nine Months Ended September 30, 2018
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, 2017
$
966

 
$
648

 
$
552

 
$
1,200

 
$
(256
)
 
$
22

 
$
—

Total realized / unrealized gains (losses)

 
 
 
 
 


 
 
 
 
 
 
Included in net income
(186
)
 
(1
)
 
(188
)
(a) 
(189
)
 
—

 
3

 
—

Included in regulatory assets
(3
)
 
—

 
—

 
—

 
(3
)
(b) 
—

 
—

Change in collateral
14

 
—

 
14

 
14

 
—

 
—

 
—

Purchases, sales, issuances and settlements

 
 
 
 
 


 
 
 
 
 
 
Purchases
215

 
34

 
181

 
215

 
—

 
—

 
—

Sales
(3
)
 
—

 
(3
)
 
(3
)
 
—

 
—

 
—

Settlements
(103
)
 
(115
)
 
—

 
(115
)
 
—

 
12

 
—

Transfers into Level 3
(21
)
 
—

 
(21
)
(c) 
(21
)
 
—

 
—

 
—

Transfers out of Level 3
(23
)
 
—

 
(23
)
(c) 
(23
)
 
—

 
—

 
—

Balance as of September 30, 2018
$
856

 
$
566

 
$
512

 
$
1,078


$
(259
)
 
$
37

 
$
—

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2018
$
154

 
$
(5
)
 
$
159

 
$
154

 
$
—

 
$
—

 
$
—


__________
(a)
Includes a reduction for the reclassification of $155 million and $347 million of realized losses due to the settlement of derivative contracts for the three and nine months ended September 30, 2018, respectively.
(b)
Includes $4 million of increases in fair value and an increase for realized losses due to settlements of $3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2018. Includes $9 million of decreases in fair value and an increase for realized losses due to settlements of $12 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2018.
(c)
Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.

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

Note 9 — Fair Value of Financial Assets and Liabilities

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2019 and 2018:
 
Exelon
 
Generation
 
PHI and Pepco
 
Operating
Revenues
 
Purchased
Power and
Fuel
 
Operating and Maintenance
 
Other, net
 
Operating
Revenues
 
Purchased
Power and
Fuel
 
Other, net
 
Operating and Maintenance
Total realized (losses) gains for the three months ended September 30, 2019
$
(25
)
 
$
(148
)
 
$
—

 
$
2

 
$
(25
)
 
$
(148
)
 
$
2

 
$
—

Total realized gains (losses) for the nine months ended September 30, 2019
122

 
(254
)
 
—

 
5

 
122

 
(254
)
 
5

 
—

Total unrealized gains (losses) for the three months ended September 30, 2019
99

 
(119
)
 
—

 
2

 
99

 
(119
)
 
2

 
—

Total unrealized gains (losses) for the nine months ended September 30, 2019
368

 
(202
)
 
2

 
5

 
368

 
(202
)
 
5

 
2

 
Exelon
 
Generation
 
PHI and Pepco
 
Operating
Revenues
 
Purchased
Power and
Fuel
 
Operating and Maintenance
 
Other, net
 
Operating
Revenues
 
Purchased
Power and
Fuel
 
Other, net
 
Operating and Maintenance
Total realized (losses) gains for the three months ended September 30, 2018
$
(176
)
 
$
(83
)
 
$
1

 
$
(1
)
 
$
(176
)
 
$
(83
)
 
$
(1
)
 
$
1

Total realized (losses) gains for the nine months ended September 30, 2018
(32
)
 
(156
)
 
3

 
(1
)
 
(32
)
 
(156
)
 
(1
)
 
3

Total unrealized (losses) for the three months ended September 30, 2018
(64
)
 
(40
)
 
—

 
(1
)
 
(64
)
 
(40
)
 
(1
)
 
—

Total unrealized gains (losses) for the nine months ended September 30, 2018
174

 
(15
)

—


(5
)
 
174

 
(15
)
 
(5
)
 
—



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

Note 9 — Fair Value of Financial Assets and Liabilities

The table below discloses the significant inputs to the forward curve used to value these positions.
Type of trade
 
Fair Value at September 30, 2019
 
Fair Value at December 31, 2018
 
Valuation
Technique
 
Unobservable
Input
 
2019 Range
 
2018 Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)
 
$
411

 
$
443

 
Discounted
Cash Flow
 
Forward power
price
 
$11
-
$167
 
$12
-
$174
 
 


 
 
 

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


 
 
 
Option
Model
 
Volatility
percentage
 
9%
-
200%
 
10%
-
277%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
 
$
67

 
$
56

 
Discounted
Cash Flow
 
Forward power
price
 
$17
-
$167
 
$14
-
$174
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mark-to-market derivatives (Exelon and ComEd)
 
$
(280
)
 
$
(249
)
 
Discounted
Cash Flow
 
Forward heat
rate(c)
 
9x
-
10x
 
10x
-
11x
 
 
 
 
 
 
 
 
Marketability
reserve
 
4%
-
7%
 
4%
-
8%
 
 
 
 
 
 
 
 
Renewable
factor
 
87%
-
119%
 
86%
-
120%

_________
(a)
The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
(b)
The fair values do not include cash collateral posted on level three positions of $304 million and $76 million as of September 30, 2019 and December 31, 2018, respectively.
(c)
Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.
10. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, interest rate risk and foreign exchange risk related to ongoing business operations.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at Generation and offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.

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

Note 10 — Derivative Financial Instruments

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

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

Note 10 — Derivative Financial Instruments

Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
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 price contracts through full requirements contracts.
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability (c)
Exchange traded future contracts for 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE
Electricity
NPNS
Fixed price contracts for all BGS requirements through full requirements contracts.
__________
(a)
See Note 4 - Regulatory Matters for additional information.
(b)
As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.
(c)
The fair value of the DPL economic hedge is not material as of September 30, 2019 and December 31, 2018 and is not presented in the fair value tables below.

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

Note 10 — Derivative Financial Instruments

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

 (a)(b)
 
Netting (a)
 
Subtotal
 
Economic
Hedges
Mark-to-market derivative assets
(current assets)
 
$
602

 
$
2,452

 
$
143

 
$
212

 
$
(2,205
)
 
$
602

 
$
—

Mark-to-market derivative assets
(noncurrent assets)
 
483

 
1,386

 
67

 
104

 
(1,074
)
 
483

 
—

Total mark-to-market derivative assets
 
1,085

 
3,838

 
210

 
316

 
(3,279
)
 
1,085

 
—

Mark-to-market derivative liabilities
(current liabilities)
 
(224
)
 
(2,550
)
 
(101
)
 
249

 
2,205

 
(197
)
 
(27
)
Mark-to-market derivative liabilities
(noncurrent liabilities)
 
(394
)
 
(1,324
)
 
(47
)
 
156

 
1,074

 
(141
)
 
(253
)
Total mark-to-market derivative liabilities
 
(618
)
 
(3,874
)
 
(148
)
 
405

 
3,279

 
(338
)
 
(280
)
Total mark-to-market derivative net assets (liabilities)
 
$
467

 
$
(36
)
 
$
62

 
$
721

 
$
—

 
$
747

 
$
(280
)
December 31, 2018
 
Exelon
 
Generation
 
ComEd
Description
 
Total
Derivatives
 
Economic
Hedges
 
Proprietary
Trading
 
Collateral

(a)(b)
 
Netting (a)
 
Subtotal
 
Economic
Hedges
Mark-to-market derivative assets
(current assets)
 
$
801

 
$
3,505

 
$
105

 
$
121

 
$
(2,930
)
 
$
801

 
$
—

Mark-to-market derivative assets
(noncurrent assets)
 
445

 
1,266

 
41

 
51

 
(913
)
 
445

 
—

Total mark-to-market derivative assets
 
1,246

 
4,771

 
146

 
172

 
(3,843
)
 
1,246

 
—

Mark-to-market derivative liabilities
(current liabilities)
 
(473
)
 
(3,429
)
 
(74
)
 
125

 
2,931

 
(447
)
 
(26
)
Mark-to-market derivative liabilities
(noncurrent liabilities)
 
(474
)
 
(1,203
)
 
(20
)
 
60

 
912

 
(251
)
 
(223
)
Total mark-to-market derivative liabilities
 
(947
)
 
(4,632
)
 
(94
)
 
185

 
3,843

 
(698
)
 
(249
)
Total mark-to-market derivative net assets (liabilities)
 
$
299

 
$
139

 
$
52

 
$
357

 
$
—

 
$
548

 
$
(249
)
_________
(a)
Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are immaterial and not reflected in the table above.
(b)
Of the collateral posted/(received), $306 million and $(94) million represents variation margin on the exchanges at September 30, 2019 and December 31, 2018 respectively.

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

Note 10 — Derivative Financial Instruments

Economic Hedges (Commodity Price Risk)
Generation. For the three and nine months ended September 30, 2019 and 2018, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.
 
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
 
2019
 
2018
 
2019
 
2018
Income Statement Location
 
Gain (Loss)
 
Gain (Loss)
Operating revenues
 
$
76

 
$
8

 
$
65

 
$
(99
)
Purchased power and fuel
 
(45
)
 
66

 
(127
)
 
(4
)
Total Exelon and Generation
 
$
31

 
$
74

 
$
(62
)
 
$
(103
)

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

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

Note 10 — Derivative Financial Instruments

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

 
$
10

 
$
683

 
—

 
$
—

Non-investment grade
74

 
38

 
36

 


 


No external ratings
 
 
 
 
 
 
 
 
 
Internally rated — investment grade
297

 
1

 
296

 


 


Internally rated — non-investment grade
175

 
24

 
151

 


 


Total
$
1,239

 
$
73

 
$
1,166

 
—

 
$
—

 
Net Credit Exposure by Type of Counterparty
 
As of
September 30, 2019
Financial institutions
 
$
1

Investor-owned utilities, marketers, power producers
 
875

Energy cooperatives and municipalities
 
255

Other
 
35

Total
 
$
1,166

_________ 
(a)
As of September 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $18 million of cash and $55 million of letters of credit. The credit collateral does not include non-liquid collateral.
Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of September 30, 2019, the Utility Registrants’ counterparty credit risk with suppliers was immaterial.
Credit-Risk-Related Contingent Features (All Registrants)
Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation

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

Note 10 — Derivative Financial Instruments

to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-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
 
September 30, 2019
 
December 31, 2018
Gross fair value of derivative contracts containing this feature(a)
 
$
(1,249
)
 
$
(1,723
)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)
 
947

 
1,105

Net fair value of derivative contracts containing this feature(c)
 
$
(302
)
 
$
(618
)
_________
(a)
Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.
(b)
Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
(c)
Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
As of September 30, 2019 and December 31, 2018, Exelon and Generation posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
 
 
September 30, 2019
 
December 31, 2018
Cash collateral posted
 
$
787

 
$
418

Letters of credit posted
 
273

 
367

Cash collateral held
 
96

 
47

Letters of credit held
 
58

 
44

Additional collateral required in the event of a credit downgrade below investment grade
 
1,481

 
2,104


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.

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

Note 10 — Derivative Financial Instruments

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 September 30, 2019, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE or DPL lost their investment grade credit ratings as of September 30, 2019, they could have been required to post incremental collateral to its counterparties of $28 million, $26 million and $11 million, respectively.
11. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, BGE, Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants' commercial paper programs as of September 30, 2019 and December 31, 2018. Generation and PECO had no commercial paper borrowings as of both September 30, 2019 and December 31, 2018.
 
Outstanding Commercial
Paper as of
 
Average Interest Rate on
Commercial Paper Borrowings as of
Commercial Paper Issuer
September 30, 2019
 
December 31, 2018
 
September 30, 2019
 
December 31, 2018
Exelon
$
519

 
$
89

 
2.50
%
 
2.15
%
ComEd
387

 
—

 
2.51
%
 
2.14
%
BGE
—

 
35

 
2.49
%
 
2.18
%
PHI
132

 
54

 
2.52
%
 
2.15
%
PEPCO
12

 
40

 
2.61
%
 
2.24
%
DPL
57

 
—

 
2.42
%
 
2.07
%
ACE
63

 
14

 
2.57
%
 
2.21
%

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

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

Note 11 — Debt and Credit Agreements

Long-Term Debt
Issuance of Long-Term Debt
During the nine months ended September 30, 2019, the following long-term debt was issued:
Company
 
Type
 
Interest Rate
 
Maturity
 
Amount
 
Use of Proceeds
Generation
 
Energy Efficiency Project Financing
 
3.95
%
 
August 31, 2020
 
$
4

 
Funding to install energy conservation measures for the Fort Meade project.
Generation
 
Energy Efficiency Project Financing
 
3.46
%
 
May 1, 2020
 
$
39

 
Funding to install energy conservation measures for the Marine Corps. Logistics Project.
ComEd
 
First Mortgage Bonds, Series 126
 
4.00
%
 
March 1, 2049
 
$
400

 
Repay a portion of ComEd’s outstanding commercial paper obligations and fund other general corporate purposes.
PECO
 
First and Refunding Mortgage Bonds
 
3.00
%
 
September 15, 2049
 
$
325

 
Repay short-term borrowings and for general corporate purposes
BGE
 
Senior Notes
 
3.20
%
 
September 15, 2049
 
$
400

 
Repay commercial paper obligations and for general corporate purposes
Pepco
 
First Mortgage Bonds
 
3.45
%
 
June 13, 2029
 
$
150

 
Repay existing indebtedness and for general corporate purposes
Pepco
 
Unsecured Tax-Exempt Bonds
 
1.70
%
 
September 1, 2022
 
$
110

 
Refinance existing indebtedness
ACE
 
First Mortgage Bonds
 
3.50
%
 
May 21, 2029
 
$
100

 
Repay existing indebtedness and for general corporate purposes
ACE
 
First Mortgage Bonds
 
4.14
%
 
May 21, 2049
 
$
50

 
Repay existing indebtedness and for general corporate purposes

Debt Covenants
As of September 30, 2019, the Registrants are in compliance with debt covenants, except for Antelope Valley's nonrecourse debt event of default as discussed below.
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default.
Antelope Valley Solar Ranch One.  In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. As of September 30, 2019, approximately $495 million was outstanding. In 2017, Generation’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.
Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code, which created an event of default for Antelope Valley’s nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the ongoing event of default and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of September 30, 2019. Further, distributions from Antelope Valley to EGR IV are currently suspended.
ExGen Renewables IV.  In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this

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

Note 11 — Debt and Credit Agreements

financing. The loan is scheduled to mature on November 28, 2024. As of September 30, 2019, $796 million was outstanding.
Although Antelope Valley’s debt is in default, it is nonrecourse to EGR IV. However, if in the future Antelope Valley were to file for bankruptcy protection as a result of events culminating from PG&E’s bankruptcy proceedings this would represent an event of default for EGR IV’s debt that would provide the lender with an opportunity to accelerate EGR IV’s debt.
See Note 13— Debt and Credit Agreements  of the Exelon 2018 Form 10-K for additional information on nonrecourse debt.
12. Income Taxes (All Registrants)
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:
 
Three Months Ended September 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
6.4
 
5.2
 
8.1
 
(0.3)
 
6.3
 
4.8
 
1.9
 
6.6
 
6.9
Qualified NDT fund income
3.2
 
7.1
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Amortization of investment tax credit, including deferred taxes on basis difference
(4.1)
 
(8.9)
 
(0.2)
 
—
 
(0.1)
 
(0.2)
 
(0.1)
 
(0.2)
 
(0.3)
Plant basis differences
(1.7)
 
—
 
(1.0)
 
(7.5)
 
(1.1)
 
(1.8)
 
(2.6)
 
(0.6)
 
(1.9)
Production tax credits and other credits
(1.2)
 
(2.7)
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Noncontrolling interests
(2.2)
 
(4.8)
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Excess deferred tax amortization
(6.5)
 
—
 
(9.9)
 
(3.6)
 
(8.0)
 
(17.7)
 
(16.3)
 
(13.5)
 
(23.3)
Other
0.7
 
0.5
 
0.4
 
(0.5)
 
(0.2)
 
0.8
 
1.0
 
(0.1)
 
0.7
Effective income tax rate
15.6%
 
17.4%
 
18.4%
 
9.1%
 
17.9%
 
6.9%
 
4.9%
 
13.2%
 
3.1%

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

Note 12 — Income Taxes

 
Three Months Ended September 30, 2018
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
U.S. Federal statutory 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
(1.2)
 
(9.0)
 
8.3
 
(3.6)
 
7.3
 
0.2
 
1.0
 
6.6
 
7.3
Qualified NDT fund income
2.4
 
5.8
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Amortization of investment tax credit, including deferred taxes on basis difference
(0.6)
 
(1.1)
 
(0.2)
 
(0.1)
 
—
 
(0.2)
 
(0.1)
 
(0.3)
 
(0.3)
Plant basis differences
(2.5)
 
—
 
(0.3)
 
(15.2)
 
(0.8)
 
(2.0)
 
(3.4)
 
(0.7)
 
(1.3)
Production tax credits and other credits
(1.2)
 
(2.9)
 
(0.1)
 
—
 
—
 
—
 
—
 
—
 
—
Noncontrolling interests
(1.1)
 
(2.8)
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Excess deferred tax amortization
(6.8)
 
—
 
(7.8)
 
(4.6)
 
(7.9)
 
(17.7)
 
(21.2)
 
(14.0)
 
(15.4)
Tax Cuts and Jobs Act of 2017
1.3
 
3.5
 
—
 
—
 
—
 
0.2
 
0.1
 
—
 
—
Other
3.2
 
5.6
 
0.3
 
0.9
 
2.6
 
0.6
 
0.3
 
0.6
 
0.3
Effective income tax rate
14.5%
 
20.1%
 
21.2%
 
(1.6)%
 
22.2%
 
2.1%
 
(2.3)%
 
13.2%
 
11.6%
 
 
 
Nine Months Ended September 30, 2019
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
U.S. Federal statutory 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
5.1
 
4.2
 
8.2
 
—
 
6.4
 
4.8
 
2.0
 
6.7
 
6.9
Qualified NDT fund income
5.3
 
11.9
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Amortization of investment tax credit, including deferred taxes on basis difference
(1.9)
 
(4.0)
 
(0.2)
 
—
 
(0.1)
 
(0.2)
 
(0.1)
 
(0.2)
 
(0.3)
Plant basis differences
(1.6)
 
—
 
(0.7)
 
(6.8)
 
(1.1)
 
(1.8)
 
(2.3)
 
(0.6)
 
(2.0)
Production tax credits and other credits
(1.0)
 
(2.1)
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Noncontrolling interests
(1.0)
 
(2.3)
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Excess deferred tax amortization
(6.0)
 
—
 
(9.2)
 
(2.9)
 
(7.9)
 
(18.6)
 
(17.3)
 
(15.0)
 
(23.4)
Other
0.8
 
(0.1)
 
0.2
 
(0.2)
 
0.1
 
0.5
 
0.7
 
0.2
 
—
Effective income tax rate
20.7%
 
28.6%
 
19.3%
 
11.1%
 
18.4%
 
5.7%
 
4.0%
 
12.1%
 
2.2%

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

Note 12 — Income Taxes

 
Nine Months Ended September 30, 2018
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
U.S. Federal statutory 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
1.7
 
(2.6)
 
8.2
 
(3.6)
 
6.6
 
2.7
 
2.4
 
6.5
 
7.3
Qualified NDT fund income
0.9
 
2.6
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Amortization of investment tax credit, including deferred taxes on basis difference
(0.9)
 
(2.2)
 
(0.2)
 
(0.1)
 
(0.1)
 
(0.2)
 
(0.1)
 
(0.3)
 
(0.3)
Plant basis differences
(2.7)
 
—
 
(0.1)
 
(15.4)
 
(0.7)
 
(1.9)
 
(2.9)
 
(0.7)
 
(1.3)
Production tax credits and other credits
(1.8)
 
(5.1)
 
(0.1)
 
—
 
—
 
—
 
—
 
—
 
—
Noncontrolling interests
(1.1)
 
(3.2)
 
—
 
—
 
—
 
—
 
—
 
—
 
—
Excess deferred tax amortization
(6.1)
 
—
 
(7.6)
 
(3.4)
 
(8.1)
 
(14.5)
 
(16.5)
 
(11.0)
 
(14.0)
Tax Cuts and Jobs Act of 2017
0.2
 
1.3
 
(0.2)
 
—
 
—
 
0.3
 
—
 
—
 
—
Other
0.4
 
2.0
 
0.1
 
—
 
0.9
 
0.3
 
—
 
0.4
 
0.9
Effective income tax rate
11.6%
 
13.8%
 
21.1%
 
(1.5)%
 
19.6%
 
7.7%
 
3.9%
 
15.9%
 
13.6%

Accounting for Uncertainty in Income Taxes
Exelon, Generation, ComEd, PHI and ACE have the following unrecognized tax benefits as of September 30, 2019 and December 31, 2018. PECO, BGE, Pepco and DPL do not have unrecognized tax benefits for the periods presented.
 
Exelon
 
Generation
 
ComEd
 
PHI
 
ACE
September 30, 2019
$
448

 
$
411

 
$
—

 
$
45

 
$
14

December 31, 2018
$
477

 
$
408

 
$
2

 
$
45

 
$
14

In 2016, the Tax Court held that Exelon was not entitled to defer a gain on its 1999 like-kind exchange transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for penalties and interest on the penalties. Exelon had fully paid the amounts assessed resulting from the Tax Court decision in 2017. In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the Tax Court’s decision. Exelon filed a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December 2018. In the first quarter of 2019, Exelon elected not to seek a further review by the U.S. Supreme Court. As a result, Exelon's and ComEd's unrecognized tax benefits decreased by approximately $33 million and $2 million, respectively, in the first quarter of 2019.

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

Note 12 — Income Taxes

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

Generation(a)

PHI(b)

ACE(b)
$
425


$
411


$
14


$
14

__________
(a)
Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate.
(b)
The unrecognized tax benefit related to PHI and ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Other Income Tax Matters
Marginal State Income Tax Rate (Exelon, Generation)
In the third quarter of 2019, Exelon reviewed and updated its marginal state income tax rates based on 2018 state apportionment rates. As a result of the rate changes, the following accounting adjustments were recorded as of September 30, 2019:
 
 
Exelon
 
Generation
Increase to deferred income tax liability
 
$
23

 
$
9

Increase to income tax expense, net of federal taxes
 
23

 
9


State Income Tax Law Changes
On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation and ComEd do not expect a material impact to their financial statements as a result of the rate change.
13. Nuclear Decommissioning (Exelon and Generation)
Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.
The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC within Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

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

Note 13 — Nuclear Decommissioning

The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2018 to September 30, 2019:
Nuclear decommissioning ARO at December 31, 2018 (a)(b)
$
10,005

Sale of Oyster Creek
(755
)
Accretion expense
361

Net increase due to changes in, and timing of, estimated future cash flows
211

Costs incurred related to decommissioning plants
(52
)
Nuclear decommissioning ARO at September 30, 2019 (a)
$
9,770

_________
(a)
Includes $127 million and $22 million as the current portion of the ARO at September 30, 2019 and December 31, 2018, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.
(b)
Includes $772 million of ARO related to Oyster Creek which was classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.
During the nine months ended September 30, 2019, Exelon's and Generation’s total nuclear ARO decreased by approximately $235 million, primarily reflecting the sale of Oyster Creek, partially offset by the accretion of the ARO liability due to the passage of time and the net impacts of ARO updates completed during the first and third quarters of 2019.
The first quarter 2019 ARO update included an increase of approximately $330 million for a change in the assumed retirement timing probabilities for certain economically challenged nuclear plants and a $110 million decrease for the impacts of revised decommissioning cost estimates for TMI which incorporate site specific decommissioning planning activities associated with the early retirement of TMI on September 20, 2019. The TMI ARO adjustment resulted in an $85 million decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. See Note 8 — Early Plant Retirements for additional information.
The third quarter 2019 ARO update included a decrease of approximately $300 million due to lower estimated costs to decommission Nine Mile Point, Ginna, Braidwood, Byron and LaSalle nuclear units resulting from the completion of updated cost studies, partially offset by an increase of approximately $280 million for other impacts that included updated cost escalation rates, primarily for labor, equipment and materials, and current discount rates. The third quarter ARO adjustment resulted in a $65 million decrease in Operating and maintenance expense within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income.
NDT Funds (Exelon and Generation)
Exelon and Generation had NDT funds totaling $12,862 million and $12,695 million at September 30, 2019 and December 31, 2018, respectively. The NDT funds included $890 million at December 31, 2018, related to Oyster Creek NDT funds which were classified as Assets held for sale in Exelon's and Generation's Consolidated Balance Sheets. See Note 3 — Mergers, Acquisitions and Dispositions for additional information regarding the sale of Oyster Creek. The NDT funds also include $156 million and $144 million for the current portion of the NDT funds at September 30, 2019 and December 31, 2018, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 17 — Supplemental Financial Information for additional information on activities of the NDT funds.
NRC Minimum Funding Requirements (Exelon and Generation)
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.
Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the

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

Note 13 — Nuclear Decommissioning

April 1, 2019 submittal. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for information regarding the amount collected from PECO ratepayers for decommissioning cost.
14. Retirement Benefits (All Registrants)
Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP are being amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan.
Defined Benefit Pension and OPEB
During the first quarter of 2019, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2019. This valuation resulted in an increase to the pension and OPEB obligations of $75 million and $36 million, respectively. Additionally, accumulated other comprehensive loss increased by $39 million (after-tax) and regulatory assets and liabilities increased by $53 million and decreased by $5 million, respectively.
The majority of the 2019 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.31%. The majority of the 2019 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.67% for funded plans and a discount rate of 4.30%.
A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, 2019 and 2018.
 
Pension Benefits
Three Months Ended September 30,
 
OPEB
Three Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
Components of net periodic benefit cost:
 
 
 
 
 
 
 
Service cost
$
89

 
$
100

 
$
23

 
$
28

Interest cost
221

 
201

 
47

 
43

Expected return on assets
(306
)
 
(312
)
 
(38
)
 
(43
)
Amortization of:
 
 
 
 
 
 
 
Prior service benefit
—

 
—

 
(45
)
 
(47
)
Actuarial loss
104

 
158

 
11

 
18

Settlement charges
7

 
—

 
—

 
—

Contractual termination benefits
1

 
—

 
—

 
—

Net periodic benefit cost
$
116

 
$
147

 
$
(2
)
 
$
(1
)


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

Note 14 — Retirement Benefits


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


 


 


 


Service cost
$
267

 
$
303

 
$
70

 
$
84

Interest cost
663

 
602

 
141

 
131

Expected return on assets
(918
)
 
(939
)
 
(115
)
 
(130
)
Amortization of:
 
 
 
 
 
 
 
Prior service cost (benefit)
—

 
1

 
(134
)
 
(140
)
Actuarial loss
310

 
472

 
34

 
50

Settlement charges
7

 
1

 
—

 
—

Contractual termination benefits
1

 
—

 
—

 
—

Net periodic benefit cost
$
330


$
440


$
(4
)

$
(5
)

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 September 30,
 
Nine Months Ended September 30,
Pension and OPEB Costs
 
2019
 
2018
 
2019
 
2018
Exelon
 
$
114

 
$
145

 
$
326

 
$
435

Generation
 
37

 
50

 
100

 
151

ComEd
 
23

 
45

 
70

 
133

PECO
 
4

 
5

 
9

 
14

BGE
 
16

 
15

 
47

 
44

PHI
 
23

 
17

 
71

 
51

Pepco
 
6

 
3

 
19

 
10

DPL
 
4

 
2

 
11

 
5

ACE
 
4

 
3

 
12

 
10



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

Note 14 — Retirement Benefits

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

 
$
44


$
101


$
126

Generation
 
14

 
23

 
41

 
65

ComEd
 
9

 
8

 
26

 
23

PECO
 
2

 
2

 
7

 
7

BGE
 
4

 
2

 
9

 
5

PHI
 
4

 
4

 
8

 
10

Pepco
 
1

 
1

 
2

 
2

DPL
 
1

 
1

 
2

 
2

ACE
 
1

 
1

 
1

 
2


15. Changes in Accumulated Other Comprehensive Income (Exelon)
The following tables present changes in Exelon's AOCI, net of tax, by component:
Three Months Ended September 30, 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
)
 
$
(2,957
)
 
$
(29
)
 
$
(2
)
 
$
(2,990
)
OCI before reclassifications
—

 
6

 
(2
)
 
—

 
4

Amounts reclassified from AOCI
—

 
21

 
—

 
2

 
23

Net current-period OCI
—

 
27

 
(2
)
 
2

 
27

Ending balance
$
(2
)
 
$
(2,930
)
 
$
(31
)
 
$
—

 
$
(2,963
)
Three Months Ended September 30, 2018
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
)
 
$
(2,890
)
 
$
(29
)
 
$
—

 
$
(2,921
)
OCI before reclassifications
—

 
5

 
2

 
—

 
7

Amounts reclassified from AOCI
—

 
45

 
—

 
—

 
45

Net current-period OCI
—

 
50

 
2

 
—

 
52

Ending balance
$
(2
)
 
$
(2,840
)
 
$
(27
)
 
$
—

 
$
(2,869
)

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

Note 15 — Changes in Accumulated Other Comprehensive Income

Nine Months Ended September 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
—

 
(32
)
 
2

 
(2
)
 
(32
)
Amounts reclassified from AOCI
—

 
62

 
—

 
2

 
64

Net current-period OCI
—

 
30

 
2

 
—

 
32

Ending balance
$
(2
)
 
$
(2,930
)
 
$
(31
)
 
$
—

 
$
(2,963
)
Nine Months Ended September 30, 2018
Gains (Losses) on Cash Flow Hedges
 
Unrealized gains (losses) on Marketable Securities
 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates (b)
 
Total
Beginning balance
$
(14
)
 
$
10

 
$
(2,998
)
 
$
(23
)
 
$
(1
)
 
$
(3,026
)
OCI before reclassifications
11

 
—

 
22

 
(4
)
 
1

 
30

Amounts reclassified from AOCI
1

 
—

 
136

 
—

 
—

 
137

Net current-period OCI
12

 
—

 
158

 
(4
)
 
1

 
167

Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard(c)
—

 
(10
)
 
—

 
—

 
—

 
(10
)
Ending balance
$
(2
)
 
$
—

 
$
(2,840
)
 
$
(27
)
 
$
—

 
$
(2,869
)
_________
(a)
AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
(b)
All amounts are net of noncontrolling interests.
(c)
Exelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million for Exelon. The amounts reclassified related to Rabbi Trusts.
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2019
 
2018
 
2019
 
2018
Pension and non-pension postretirement benefit plans:
 
 
 
 
 
 
 
Prior service benefit reclassified to periodic benefit cost
$
6

 
$
6

 
$
18

 
$
18

Actuarial loss reclassified to periodic benefit cost
(13
)
 
(21
)
 
(39
)
 
(65
)
Pension and non-pension postretirement benefit plans valuation adjustment
—

 
(2
)
 
14

 
(8
)

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

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

Note 16 — Commitments and Contingencies

Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL and ACE as of September 30, 2019:
Description
Exelon
 
PHI
 
Pepco
 
DPL
 
ACE
Total commitments
$
513

 
$
320

 
$
120

 
$
89

 
$
111

Remaining commitments(a)
112

 
82

 
67

 
9

 
6


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

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

Note 16 — Commitments and Contingencies

Commercial Commitments (All Registrants). The Registrants’ commercial commitments as of September 30, 2019, representing commitments potentially triggered by future events were as follows:
 
 
 
Expiration within
 
Total
 
2019
 
2020
 
2021
 
2022
 
2023
 
2024 and beyond
Exelon
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit
$
1,718

 
$
1,192

 
$
515

 
$
11

 
$
—

 
$
—

 
$
—

Surety bonds(a)
991

 
315

 
638

 
38

 
—

 
—

 
—

Financing trust guarantees
378

 
—

 
—

 
—

 
—

 
—

 
378

Guaranteed lease residual values(b)
26

 
—

 
2

 
3

 
4

 
3

 
15

Total commercial commitments
$
3,113

 
$
1,507

 
$
1,155

 
$
52

 
$
4


$
3

 
$
393

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Generation
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit
$
1,686

 
$
1,179

 
$
496

 
$
11

 
$
—

 
$
—

 
$
—

Surety bonds(a)
790

 
298

 
492

 
—

 
—

 
—

 
—

Total commercial commitments
$
2,476

 
$
1,477

 
$
988

 
$
11

 
$
—

 
$
—

 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
ComEd
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit
$
7

 
$
4

 
$
3

 
$
—

 
$
—

 
$
—

 
$
—

Surety bonds(a)
50

 
5

 
43

 
2

 
—

 
—

 
—

Financing trust guarantees
200

 
—

 
—

 
—

 
—

 
—

 
200

Total commercial commitments
$
257

 
$
9

 
$
46

 
$
2

 
$
—

 
$
—

 
$
200

 
 
 
 
 
 
 
 
 
 
 
 
 
 
PECO
 
 
 
 
 
 
 
 
 
 
 
 
 
Surety bonds(a)
$
9

 
$
1

 
$
8

 
$
—

 
$
—

 
$
—

 
$
—

Financing trust guarantees
178

 
—

 
—

 
—

 
—

 
—

 
178

Total commercial commitments
$
187

 
$
1

 
$
8

 
$
—

 
$
—

 
$
—

 
$
178

 
 
 
 
 
 
 
 
 
 
 
 
 
 
BGE
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit
$
8

 
$
2

 
$
6

 
$
—

 
$
—

 
$
—

 
$
—

Surety bonds(a)
17

 
2

 
15

 
—

 
—

 
—

 
—

Total commercial commitments
$
25

 
$
4

 
$
21

 
$
—

 
$
—

 
$
—

 
$
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
PHI
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit
$
11

 
$
1

 
$
10

 
$
—

 
$
—

 
$
—

 
$
—

Surety bonds(a)
24

 
5

 
19

 
—

 
—

 
—

 
—

Guaranteed lease residual values(b)
26

 
—

 
2

 
3

 
4

 
3

 
15

Total commercial commitments
$
61

 
$
6

 
$
31

 
$
3

 
$
4

 
$
3

 
$
15

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pepco
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit
$
10

 
$
—

 
$
10

 
$
—

 
$
—

 
$
—

 
$
—

Surety bonds(a)
17

 
2

 
15

 
—

 
—

 
—

 
—

Guaranteed lease residual values(b)
9

 
—

 
—

 
1

 
1

 
1

 
6

Total commercial commitments
$
36

 
$
2

 
$
25

 
$
1

 
$
1

 
$
1

 
$
6

 
 
 
 
 
 
 
 
 
 
 
 
 
 
DPL
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of credit
$
1

 
$
1

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Surety bonds(a)
4

 
2

 
2

 
—

 
—

 
—

 
—

Guaranteed lease residual values(b)
11

 
—

 
1

 
1

 
2

 
1

 
6

Total commercial commitments
$
16

 
$
3

 
$
3

 
$
1

 
$
2

 
$
1

 
$
6

 
 
 
 
 
 
 
 
 
 
 
 
 
 
ACE
 
 
 
 
 
 
 
 
 
 
 
 
 
Surety bonds(a)
$
3

 
$
1

 
$
2

 
$
—

 
$
—

 
$
—

 
$
—

Guaranteed lease residual values(b)
7

 
—

 
1

 
1

 
1

 
1

 
3

Total commercial commitments
$
10

 
$
1

 
$
3

 
$
1

 
$
1

 
$
1

 
$
3


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

Note 16 — Commitments and Contingencies

_________
(a)
Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(b)
Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $68 million guaranteed by Exelon and PHI, of which $22 million, $29 million and $17 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 in the Registrants' financial statements.
MGP Sites (Exelon, ComEd, PECO, BGE, PHI and DPL). ComEd, PECO, BGE and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
•
ComEd has identified 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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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 16 — Commitments and Contingencies

As of September 30, 2019 and December 31, 2018, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
 
September 30, 2019
 
December 31, 2018
 
Total environmental
investigation and
remediation liabilities
 
Portion of total related to
MGP investigation and
remediation
 
Total environmental
investigation and
remediation liabilities
 
Portion of total related to
MGP investigation and
remediation
Exelon
$
507


$
346

 
$
496


$
356

Generation
107

 
—

 
108

 
—

ComEd
328

 
327

 
329

 
327

PECO
20

 
18

 
27

 
25

BGE
3

 
1

 
5

 
4

PHI
49


—

 
27


—

Pepco
47

 
—

 
25

 
—

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 the final remedy. The ROD modified the EPA’s previously proposed plan for partial excavation of the radiological materials by reducing the depths of the excavation. The ROD also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in the 2020 - 2021 time frame. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. The EPA has established a deadline of October 2019 for the PRPs to provide a good faith offer to conduct, or finance, the Remedial Action work. This schedule can be extended by the EPA pending completion of the Remedial Design. The estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required remediation remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Generation’s associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.
One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial statements.
In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater RI/FS. The

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

Note 16 — Commitments and Contingencies

purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $20 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future financial statements.
In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million from all PRPs. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 2020 so that settlement discussions could proceed. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above.
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 Remediation Investigation (RI)/ Feasibility Study (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. Once the RI work is completed, Pepco and Generation will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Generation will then proceed to develop a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the RI and FS, and approval by the DOEE, by September 16, 2021.
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 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

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

Note 16 — Commitments and Contingencies

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. The District of Columbia Council has set a deadline of December 31, 2019 for completion of the Record of Decision. An appropriate liability for Pepco’s share of investigation costs has been accrued and is included in the table above.
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 based on DOEE’s stated position following a series of meetings attended by representatives from the Anacostia Leadership Council and the Consultative Working Group. A draft FS, which Pepco believes will include the process to identify potential short-term remedies and actions based on the technical findings in the RI report and their estimated costs to the extent possible, is being prepared by DOEE and is expected later in the fourth quarter of 2019. DOEE and likely the National Park Service will continue to oversee ongoing remediation efforts and potential longer-term remedies for the Anacostia River. Pepco has 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, there is a complementary statutory program that requires an assessment to determine if any natural resources have been damaged as a result of the contamination that is being remediated, and, if so, that a plan be developed by the federal, state and local Natural Resource Damage Trustees, who are defined by CERCLA as the responsible parties for the restoration or compensation for any loss of those resources from the environmental contaminants at the site. If natural resources cannot be restored, then compensation for the injury can be sought from the responsible parties. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also effectively restore habitat. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process it cannot reasonably estimate the range of loss.
Litigation and Regulatory Matters
Asbestos Personal Injury Claims (Exelon and Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.
At September 30, 2019 and December 31, 2018, Exelon and Generation had recorded estimated liabilities of approximately $83 million and $79 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2019, approximately $25 million of this amount related to 257 open claims presented to Generation, while the remaining $58 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.
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.
City of Everett Tax Increment Financing Agreement (Exelon and Generation). On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. Generation vigorously contested the City’s claims before the EACC and will continue to do so in the Massachusetts Superior Court proceeding. Generation continues to believe that the City’s claim lacks merit. Accordingly, Generation has not recorded a liability for payment resulting from such a revocation, nor can Generation estimate a reasonably possible range of loss, if any, associated with any such revocation. Further,

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

Note 16 — Commitments and Contingencies

it is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 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 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 U.S. Attorney's Office for the Northern District of Illinois requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it has also opened an investigation into their lobbying activities. Exelon and ComEd have cooperated fully and intend to continue to cooperate fully and expeditiously with the U.S. Attorney’s Office and the SEC. Exelon and ComEd cannot predict the outcome of the subpoenas or the SEC investigation.
General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
17. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
 
Taxes other than income
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Three Months Ended September 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility taxes(a)
$
241

 
$
29

 
$
66

 
$
38

 
$
21

 
$
86

 
$
81

 
$
5

 
$
—

Property
148

 
66

 
7

 
5

 
39

 
31

 
21

 
9

 
—

Payroll
57

 
28

 
7

 
3

 
4

 
6

 
2

 
1

 
1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility taxes(a)
$
253

 
$
32

 
$
67

 
$
39

 
$
23

 
$
92

 
$
87

 
$
5

 
$
—

Property
145

 
70

 
7

 
4

 
37

 
26

 
16

 
9

 
—

Payroll
58

 
31

 
6

 
3

 
4

 
5

 
1

 
1

 
1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility taxes(a)
$
672

 
$
87

 
$
183

 
$
102

 
$
68

 
$
231

 
$
217

 
$
14

 
$
—

Property
444

 
205

 
22

 
12

 
114

 
91

 
64

 
25

 
2

Payroll
185

 
92

 
21

 
11

 
13

 
20

 
5

 
3

 
2

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Utility taxes(a)
$
705

 
$
92

 
$
188

 
$
102

 
$
70

 
$
253

 
$
238

 
$
15

 
$
—

Property
416

 
204

 
22

 
12

 
106

 
71

 
45

 
24

 
2

Payroll
191

 
99

 
20

 
11

 
12

 
19

 
5

 
3

 
2

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

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

Note 17 — Supplemental Financial Information

 
Other, Net
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Three Months Ended September 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning-related activities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net realized income on NDT funds(a)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
$
67

 
$
67

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Non-regulatory agreement units
33

 
33

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Net unrealized gains on NDT funds
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
89

 
89

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Non-regulatory agreement units
55

 
55

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Regulatory offset to NDT fund-related activities(b)
(125
)
 
(125
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Decommissioning-related activities
119

 
119

 
—

 
—

 
—


—

 
—

 
—

 
—

AFUDC — Equity
22

 
—

 
4

 
3

 
6

 
9

 
7

 
1

 
1

Non-service net periodic benefit cost
(2
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Three Months Ended September 30, 2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning-related activities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net realized income on NDT funds(a)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
$
214

 
$
214

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Non-regulatory agreement units
58

 
58

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Net unrealized (losses) gains on NDT funds
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
(66
)
 
(66
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Non-regulatory agreement units
72

 
72

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Regulatory offset to NDT fund-related activities(b)
(110
)
 
(110
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Decommissioning-related activities
168

 
168

 
—

 
—

 
—


—


—

 
—

 
—

AFUDC — Equity
16

 
—

 
4

 
1

 
5

 
6

 
6

 
—

 
—

Non-service net periodic benefit cost
(12
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—


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

Note 17 — Supplemental Financial Information

 
Other, Net
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Nine Months Ended September 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning-related activities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net realized income on NDT funds(a)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
$
197

 
$
197

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Non-regulatory agreement units
316

 
316

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Net unrealized gains on NDT funds
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
565

 
565

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Non-regulatory agreement units
236

 
236

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Regulatory offset to NDT fund-related activities(b)
(611
)
 
(611
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Decommissioning-related activities
703

 
703

 
—

 
—

 
—

 
—

 
—

 
—

 
—

AFUDC — Equity
64

 
—

 
13

 
9

 
16

 
26

 
18

 
3

 
4

Non-service net periodic benefit cost
8

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Decommissioning-related activities:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net realized income on NDT funds(a)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
$
476

 
$
476

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

Non-regulatory agreement units
257

 
257

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Net unrealized losses on NDT funds
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Regulatory agreement units
(335
)
 
(335
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Non-regulatory agreement units
(143
)
 
(143
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Regulatory offset to NDT fund-related activities(b)
(110
)
 
(110
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Decommissioning-related activities
145

 
145

 
—

 
—

 
—

 
—


—

 
—

 
—

AFUDC — Equity
47

 
—

 
12

 
3

 
13

 
19

 
17

 
2

 
—

Non-service net periodic benefit cost
(33
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

_________
(a)
Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
(b)
Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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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
Nine Months Ended September 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, plant and equipment(a)
$
2,803

 
$
1,184

 
$
661

 
$
225

 
$
263

 
$
405

 
$
178

 
$
109

 
$
89

Amortization of regulatory assets(a)
390

 
—

 
106

 
22

 
105

 
157

 
103

 
29

 
25

Amortization of intangible assets, net(a)
44

 
37

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Amortization of energy contract assets and liabilities(b)
14

 
14

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Nuclear fuel(c)
771

 
771

 
—

 
—

 
—

 
—

 
—

 
—

 
—

ARO accretion(d)
371

 
371

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total depreciation, amortization and accretion
$
4,393


$
2,377


$
767


$
247


$
368

 
$
562

 
$
281


$
138


$
114

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Property, plant and equipment(a)
$
2,829

 
$
1,347

 
$
613

 
$
204

 
$
249

 
$
355

 
$
161

 
$
97

 
$
70

Amortization of regulatory assets(a)
412

 
—

 
83

 
20

 
109

 
200

 
125

 
38

 
37

Amortization of intangible assets, net(a)
43

 
36

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Amortization of energy contract assets and liabilities(b)
8

 
8

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Nuclear fuel(c)
852

 
852

 
—

 
—

 
—

 
—

 
—

 
—

 
—

ARO accretion(d)
367

 
365

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Total depreciation, amortization and accretion
$
4,511


$
2,608


$
696


$
224


$
358

 
$
555

 
$
286


$
135


$
107

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

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

Note 17 — Supplemental Financial Information

 
Other non-cash operating activities
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Nine Months Ended September 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and non-pension postretirement benefit costs
$
324

 
$
98

 
$
70

 
$
9

 
$
45

 
$
71

 
$
19

 
$
11

 
$
12

Provision for uncollectible accounts
89

 
20

 
26

 
22

 
5

 
16

 
7

 
2

 
6

Other decommissioning-related activity(a)
(400
)
 
(400
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Energy-related options(b)
21

 
21

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Amortization of rate stabilization deferral
(8
)
 
—

 
—

 
—

 
—

 
(8
)
 
(9
)
 
1

 
—

Discrete impacts from EIMA and FEJA(c)
80

 
—

 
80

 
—

 
—

 
—

 
—

 
—

 
—

Long-term incentive plan
33

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Amortization of operating ROU asset
193

 
138

 
2

 
—

 
23

 
26

 
6

 
7

 
4

Change in environmental liabilities
23

 
—

 
—

 
—

 
—

 
23

 
23

 
—

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30, 2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and non-pension postretirement benefit costs
$
435

 
$
151

 
$
133

 
$
14

 
$
43

 
$
51

 
$
10

 
$
5

 
$
10

Provision for uncollectible accounts
133

 
38

 
30

 
25

 
6

 
32

 
12

 
6

 
14

Other decommissioning-related activity(a)
(39
)
 
(39
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Energy-related options(b)
4

 
4

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Amortization of rate stabilization deferral
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Discrete impacts from EIMA and FEJA(c)
27

 
—

 
27

 
—

 
—

 
—

 
—

 
—

 
—

Long-term incentive plan
84

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Asset retirement costs
20

 
—

 
—

 
—

 
—

 
20

 
22

 
(1
)
 
(1
)
_______
(a)
Includes the elimination of decommissioning-related activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
(b)
Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded in Operating revenues and expenses.
(c)
Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 6 — Regulatory Matters for additional information.


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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
September 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
1,683

 
$
1,019

 
$
76

 
$
224

 
$
130

 
$
99

 
$
18

 
$
11

 
$
13

Restricted cash
309

 
126

 
124

 
6

 
1

 
38

 
34

 
—

 
3

Restricted cash included in other long-term assets
186

 
—

 
171

 
—

 
—

 
15

 
—

 
—

 
15

Total cash, cash equivalents and restricted cash
$
2,178

 
$
1,145

 
$
371

 
$
230

 
$
131

 
$
152

 
$
52

 
$
11

 
$
31

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

 
$
750

 
$
135

 
$
130

 
$
7

 
$
124

 
$
16

 
$
23

 
$
7

Restricted 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

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30, 2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
1,918

 
$
1,187

 
$
124

 
$
102

 
$
113

 
$
153

 
$
12

 
$
110

 
$
11

Restricted cash
240

 
152

 
12

 
5

 
3

 
42

 
35

 
—

 
7

Restricted cash included in other long-term assets
163

 
—

 
144

 
—

 
—

 
19

 
—

 
—

 
19

Total cash, cash equivalents and restricted cash
$
2,321

 
$
1,339

 
$
280

 
$
107

 
$
116

 
$
214

 
$
47

 
$
110

 
$
37

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2017
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
898

 
$
416

 
$
76

 
$
271

 
$
17

 
$
30

 
$
5

 
$
2

 
$
2

Restricted cash
207

 
138

 
5

 
4

 
1

 
42

 
35

 
—

 
6

Restricted cash included in other long-term assets
85

 
—

 
63

 
—

 
—

 
23

 
—

 
—

 
23

Total cash, cash equivalents and restricted cash
$
1,190

 
$
554

 
$
144

 
$
275

 
$
18

 
$
95

 
$
40

 
$
2

 
$
31

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K. 
Supplemental Balance Sheet Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
 
Unbilled customer revenues
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
September 30, 2019
$
1,256

 
$
676

 
$
212

 
$
102

 
$
103

 
$
163

 
$
91

 
$
38

 
$
34

December 31, 2018
1,656

 
965

 
223

 
114

 
168

 
186

 
97

 
59

 
30



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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

 
Accrued expenses
 
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
September 30, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Compensation-related accruals(a)
$
880

 
$
336

 
$
133

 
$
48

 
$
63

 
$
86

 
$
26

 
$
17

 
$
13

Taxes accrued
431

 
247

 
56

 
13

 
64

 
80

 
61

 
17

 
3

Interest accrued
421

 
106

 
62

 
33

 
36

 
78

 
37

 
20

 
19

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Compensation-related accruals(a)
$
1,191

 
$
479

 
$
187

 
$
49

 
$
68

 
$
99

 
$
29

 
$
19

 
$
12

Taxes accrued
412

 
226

 
71

 
28

 
46

 
74

 
58

 
4

 
5

Interest accrued
334

 
77

 
105

 
33

 
39

 
50

 
25

 
8

 
12

_________
(a)
Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
18. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources at each of the Registrants.
Exelon has 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 ISO-NY.
•
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’

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

Note 18 — Segment Information

presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.
During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region is no longer regularly reviewed as a separate region by the CODM nor is it presented separately in any external information presented to third parties. Information for the New England region is reviewed by the CODM as part of Other Power Regions. Exelon and Generation retrospectively applied this change.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2019 and 2018 is as follows:
Three Months Ended September 30, 2019 and 2018
 
Generation(a)
 
ComEd
 
PECO
 
BGE
 
PHI
 
Other(b)
 
Intersegment
Eliminations
 
Exelon
Operating revenues(c):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
Competitive businesses electric revenues
$
4,314

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(275
)
 
$
4,039

Competitive businesses natural gas revenues
265

 
—

 
—

 
—

 
—

 
—

 
1

 
266

Competitive businesses other revenues
195

 
—

 
—

 
—

 
—

 
—

 
(1
)
 
194

Rate-regulated electric revenues
—

 
1,583

 
716

 
619

 
1,357

 
—

 
(7
)
 
4,268

Rate-regulated natural gas revenues
—

 
—

 
62

 
84

 
20

 
—

 
(3
)
 
163

Shared service and other revenues
—

 
—

 
—

 
—

 
3

 
474

 
(478
)
 
(1
)
Total operating revenues
$
4,774

 
$
1,583

 
$
778

 
$
703

 
$
1,380

 
$
474

 
$
(763
)
 
$
8,929



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

Note 18 — Segment Information

 
Generation(a)
 
ComEd
 
PECO
 
BGE
 
PHI
 
Other(b)
 
Intersegment
Eliminations
 
Exelon
2018
Competitive businesses electric revenues
$
4,741

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(306
)
 
$
4,435

Competitive businesses natural gas revenues
397

 
—

 
—

 
—

 
—

 
—

 
—

 
397

Competitive businesses other revenues
140

 
—

 
—

 
—

 
—

 
—

 
(1
)
 
139

Rate-regulated electric revenues
—

 
1,598

 
700

 
645

 
1,334

 
—

 
(7
)
 
4,270

Rate-regulated natural gas revenues
—

 
—

 
57

 
86

 
24

 
—

 
(5
)
 
162

Shared service and other revenues
—

 
—

 
—

 
—

 
3

 
458

 
(461
)
 
—

Total operating revenues
$
5,278

 
$
1,598

 
$
757

 
$
731

 
$
1,361

 
$
458

 
$
(780
)
 
$
9,403

Intersegment revenues(d):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
275

 
$
4

 
$
1

 
$
6

 
$
4

 
$
474

 
$
(764
)
 
$
—

2018
308

 
4

 
2

 
6

 
3

 
456

 
(779
)
 
—

Depreciation and amortization:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
407

 
$
259

 
$
83

 
$
116

 
$
193

 
$
25

 
$
—

 
$
1,083

2018
468

 
237

 
75

 
110

 
192

 
23

 
—

 
1,105

Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
4,274

 
$
1,256

 
$
595

 
$
612

 
$
1,124

 
$
457

 
$
(759
)
 
$
7,559

2018
4,961

 
1,275

 
603

 
628

 
1,116

 
459

 
(790
)
 
8,252

Interest expense, net:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
109

 
$
91

 
$
33

 
$
31

 
$
66

 
$
79

 
$
—

 
$
409

2018
101

 
85

 
32

 
27

 
65

 
83

 
—

 
393

Income (loss) before income taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
501

 
$
245

 
$
154

 
$
67

 
$
203

 
$
(68
)
 
$
—

 
$
1,102

2018
389

 
245

 
124

 
81

 
191

 
(83
)
 
—

 
947

Income Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
87

 
$
45

 
$
14

 
$
12

 
$
14

 
$
—

 
$
—

 
$
172

2018
78

 
52

 
(2
)
 
18

 
4

 
(13
)
 
—

 
137

Net income (loss):
 
 
 
 
 
 
 
 
 
 
 
 
 
 

2019
$
244

 
$
200

 
$
140

 
$
55

 
$
189

 
$
(68
)
 
$
—

 
$
760

2018
300

 
193

 
126

 
63

 
187

 
(69
)
 
—

 
800

Capital Expenditures
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
392

 
$
452

 
$
228

 
$
300

 
$
308

 
$
7

 
$
—

 
$
1,687

2018
362

 
514

 
204

 
233

 
359

 
18

 
—

 
1,690



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

Note 18 — Segment Information

__________
(a)
Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $43 million, sales to BGE of $65 million, sales to Pepco of $65 million, sales to DPL of $14 million and sales to ACE of $3 million in the Mid-Atlantic region, and sales to ComEd of $83 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $35 million, sales to BGE of $69 million, sales to Pepco of $46 million, sales to DPL of $26 million and sales to ACE of $10 million in the Mid-Atlantic region, and sales to ComEd of $122 million in the Midwest region, which eliminate upon consolidation.
(b)
Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(c)
Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(d)
Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

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

Note 18 — Segment Information

PHI:
 
Pepco
 
DPL
 
ACE
 
Other(b)
 
Intersegment
Eliminations
 
PHI
Operating revenues(a):
2019
 
 
 
 
 
 
 
 
 
 
 
Rate-regulated electric revenues
$
642

 
$
299

 
$
419

 
$
—

 
$
(3
)
 
$
1,357

Rate-regulated natural gas revenues
—

 
20

 
—

 
—

 
—

 
20

Shared service and other revenues
—

 
—

 
—

 
92

 
(89
)
 
3

Total operating revenues
$
642

 
$
319

 
$
419

 
$
92

 
$
(92
)
 
$
1,380

2018
 
 
 
 
 
 
 
 
 
 
 
Rate-regulated electric revenues
$
628

 
$
304

 
$
406

 
$
—

 
$
(4
)
 
$
1,334

Rate-regulated natural gas revenues
—

 
24

 
—

 
—

 
—

 
24

Shared service and other revenues
—

 
—

 
—

 
103

 
(100
)
 
3

Total operating revenues
$
628

 
$
328

 
$
406

 
$
103

 
$
(104
)
 
$
1,361

Intersegment revenues:
 
 
 
 
 
 
 
 
 
 
 
2019
$
2

 
$
1

 
$
1

 
$
93

 
$
(93
)
 
$
4

2018
2

 
2

 
1

 
103

 
(105
)
 
3

Depreciation and amortization:
 
 
 
 
 
 
 
 
 
 
 
2019
$
95

 
$
46

 
$
43

 
$
9

 
$
—

 
$
193

2018
99

 
47

 
38

 
8

 
—

 
192

Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
2019
$
515

 
$
268

 
$
340

 
$
95

 
$
(94
)
 
$
1,124

2018
516

 
277

 
322

 
105

 
(104
)
 
1,116

Interest expense, net:
 
 
 
 
 
 
 
 
 
 
 
2019
$
33

 
$
15

 
$
15

 
$
3

 
$
—

 
$
66

2018
32

 
15

 
16

 
2

 
—

 
65

Income (loss) before income taxes:
 
 
 
 
 
 
 
 
 
 
 
2019
$
103

 
$
38

 
$
65

 
$
192

 
$
(195
)
 
$
203

2018
87

 
38

 
69

 
179

 
(182
)
 
191

Income Taxes:
 
 
 
 
 
 
 
 
 
 
 
2019
$
5

 
$
5

 
$
2

 
$
3

 
$
(1
)
 
$
14

2018
(2
)
 
5

 
8

 
(8
)
 
1

 
4

Net income (loss):
 
 
 
 
 
 
 
 
 
 
 
2019
$
98

 
$
33

 
$
63

 
$
(9
)
 
$
4

 
$
189

2018
89

 
33

 
61

 
1

 
3

 
187

Capital Expenditures
 
 
 
 
 
 
 
 
 
 
 
2019
$
157

 
$
85

 
$
73

 
$
(7
)
 
$
—

 
$
308

2018
188

 
88

 
77

 
6

 
—

 
359


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

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

Note 18 — Segment Information

by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
 
Three Months Ended September 30, 2019
 
Revenues from external customers(a)
 
Intersegment
revenues

Total
Revenues
 
Contracts with customers
 
Other(b)
 
Total
 
 
Mid-Atlantic
$
1,351

 
$
10

 
$
1,361

 
$
3

 
$
1,364

Midwest
1,052

 
47

 
1,099

 
(17
)
 
1,082

New York
414

 
15

 
429

 
—

 
429

ERCOT
288

 
72

 
360

 
5

 
365

Other Power Regions
873

 
192

 
1,065

 
(25
)
 
1,040

Total Competitive Businesses Electric Revenues
3,978

 
336

 
4,314

 
(34
)
 
4,280

Competitive Businesses Natural Gas Revenues
160

 
105

 
265

 
34

 
299

Competitive Businesses Other Revenues(c)
112

 
83

 
195

 
—

 
195

Total Generation Consolidated Operating Revenues
$
4,250

 
$
524

 
$
4,774

 
$
—

 
$
4,774


 
Three Months Ended September 30, 2018
 
Revenues from external customers(a)
 
Intersegment
revenues
 
Total
Revenues
 
Contracts with customers
 
Other(b)
 
Total
 
 
Mid-Atlantic
$
1,397

 
$
52

 
$
1,449

 
$
7

 
$
1,456

Midwest
1,095

 
26

 
1,121

 
(4
)
 
1,117

New York
475

 
(6
)
 
469

 
—

 
469

ERCOT
156

 
289

 
445

 
(1
)
 
444

Other Power Regions
959

 
298

 
1,257

 
(45
)
 
1,212

Total Competitive Businesses Electric Revenues
4,082

 
659

 
4,741

 
(43
)
 
4,698

Competitive Businesses Natural Gas Revenues
200

 
197

 
397

 
43

 
440

Competitive Businesses Other Revenues(c)
130

 
10

 
140

 
—

 
140

Total Generation Consolidated Operating Revenues
$
4,412

 
$
866

 
$
5,278

 
$
—

 
$
5,278

__________
(a)
Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)
Includes revenues from derivatives and leases.
(c)
Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $77 million and $6 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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

Note 18 — Segment Information

Revenues net of purchased power and fuel expense (Generation):
 
Three Months Ended September 30, 2019
 
Three Months Ended September 30, 2018
 
RNF
from external
customers(a)
 
Intersegment
RNF
 
Total RNF
 
RNF
from external
customers(a)
 
Intersegment
RNF
 
Total RNF
Mid-Atlantic
$
684

 
$
5

 
$
689

 
$
746

 
$
17

 
$
763

Midwest
763

 
(16
)
 
747

 
763

 
5

 
768

New York
288

 
3

 
291

 
290

 
2

 
292

ERCOT
76

 
(4
)
 
72

 
161

 
(63
)
 
98

Other Power Regions
212

 
(28
)
 
184

 
226

 
(46
)
 
180

Total Revenues net of purchased power and fuel for Reportable Segments
2,023


(40
)

1,983


2,186


(85
)

2,101

Other(b)
100

 
40

 
140

 
112

 
85

 
197

Total Generation Revenues net of purchased power and fuel expense
$
2,123


$
—


$
2,123


$
2,298


$
—


$
2,298

__________
(a)
Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)
Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $17 million and $71 million in 2019 and 2018, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of $3 million and $18 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

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

Note 18 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):
 
Three Months Ended September 30, 2019
Revenues from contracts with customers
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Rate-regulated electric revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
865

 
$
479

 
$
352

 
$
741

 
$
311

 
$
178

 
$
252

Small commercial & industrial
393

 
109

 
64

 
147

 
41

 
48

 
58

Large commercial & industrial
141

 
63

 
116

 
297

 
222

 
26

 
49

Public authorities & electric railroads
12

 
9

 
7

 
17

 
11

 
3

 
3

Other(a)
222

 
63

 
82

 
164

 
58

 
50

 
56

Total rate-regulated electric revenues(b)
$
1,633

 
$
723

 
$
621

 
$
1,366

 
$
643

 
$
305

 
$
418

Rate-regulated natural gas revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
—

 
$
38

 
$
49

 
$
9

 
$
—

 
$
9

 
$
—

Small commercial & industrial
—

 
17

 
9

 
4

 
—

 
4

 
—

Large commercial & industrial
—

 
—

 
20

 
1

 
—

 
1

 
—

Transportation
—

 
5

 
—

 
4

 
—

 
4

 
—

Other(c)
—

 
2

 
5

 
2

 
—

 
2

 
—

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

 
$
62

 
$
83

 
$
20

 
$
—

 
$
20

 
$
—

Total rate-regulated revenues from contracts with customers
$
1,633

 
$
785

 
$
704

 
$
1,386

 
$
643

 
$
325

 
$
418

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from alternative revenue programs
$
(56
)
 
$
(11
)
 
$
(5
)
 
$
(9
)
 
$
(3
)
 
$
(6
)
 
$
1

Other rate-regulated electric revenues(e)
6

 
4

 
3

 
3

 
2

 
—

 
—

Other rate-regulated natural gas revenues(e)
—

 
—

 
1

 
—

 
—

 
—

 
—

Total other revenues
$
(50
)
 
$
(7
)
 
$
(1
)
 
$
(6
)
 
$
(1
)
 
$
(6
)
 
$
1

Total rate-regulated revenues for reportable segments
$
1,583

 
$
778

 
$
703

 
$
1,380

 
$
642

 
$
319

 
$
419


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

Note 18 — Segment Information

 
Three Months Ended September 30, 2018
Revenues from contracts with customers
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Rate-regulated electric revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
861

 
$
458

 
$
366

 
$
726

 
$
306

 
$
180

 
$
240

Small commercial & industrial
391

 
108

 
68

 
140

 
39

 
48

 
53

Large commercial & industrial
131

 
64

 
117

 
303

 
230

 
25

 
48

Public authorities & electric railroads
11

 
7

 
7

 
14

 
8

 
3

 
3

Other(a)
212

 
59

 
91

 
156

 
47

 
47

 
63

Total rate-regulated electric revenues(b)
$
1,606

 
$
696

 
$
649

 
$
1,339

 
$
630

 
$
303

 
$
407

Rate-regulated natural gas revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
—

 
$
36

 
$
46

 
$
8

 
$
—

 
$
8

 
$
—

Small commercial & industrial
—

 
15

 
8

 
5

 
—

 
5

 
—

Large commercial & industrial
—

 
—

 
17

 
2

 
—

 
2

 
—

Transportation
—

 
5

 
—

 
3

 
—

 
3

 
—

Other(c)
—

 
1

 
12

 
6

 
—

 
6

 
—

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

 
$
57

 
$
83

 
$
24

 
$
—

 
$
24

 
$
—

Total rate-regulated revenues from contracts with customers
$
1,606

 
$
753

 
$
732

 
$
1,363

 
$
630

 
$
327

 
$
407

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from alternative revenue programs
$
(15
)
 
$
1

 
$
(6
)
 
$
(5
)
 
$
(4
)
 
$
—

 
$
(1
)
Other rate-regulated electric revenues(e)
7

 
3

 
4

 
3

 
2

 
1

 
—

Other rate-regulated natural gas revenues(e)
—

 
—

 
1

 
—

 
—

 
—

 
—

Total other revenues
$
(8
)
 
$
4

 
$
(1
)
 
$
(2
)
 
$
(2
)
 
$
1

 
$
(1
)
Total rate-regulated revenues for reportable segments
$
1,598

 
$
757

 
$
731

 
$
1,361

 
$
628

 
$
328

 
$
406

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

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

Note 18 — Segment Information

Nine Months Ended September 30, 2019 and 2018
 
Generation(a)
 
ComEd
 
PECO
 
BGE
 
PHI
 
Other(b)
 
Intersegment
Eliminations
 
Exelon
Operating revenues(c):
2019
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Competitive businesses electric revenues
$
12,365

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(840
)
 
$
11,525

Competitive businesses natural gas revenues
1,479

 
—

 
—

 
—

 
—

 
—

 
—

 
1,479

Competitive businesses other revenues
436

 
—

 
—

 
—

 
—

 
—

 
(4
)
 
432

Rate-regulated electric revenues
—

 
4,342

 
1,901

 
1,817

 
3,574

 
—

 
(25
)
 
11,609

Rate-regulated natural gas revenues
—

 
—

 
432

 
510

 
116

 
—

 
(12
)
 
1,046

Shared service and other revenues
—

 
—

 
—

 
—

 
10

 
1,410

 
(1,415
)
 
5

Total operating revenues
$
14,280

 
$
4,342

 
$
2,333

 
$
2,327

 
$
3,700

 
$
1,410

 
$
(2,296
)
 
$
26,096

2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Competitive businesses electric revenues
$
13,190

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 
$
(969
)
 
$
12,221

Competitive businesses natural gas revenues
1,839

 
—

 
—

 
—

 
—

 
—

 
(8
)
 
1,831

Competitive businesses other revenues
339

 
—

 
—

 
—

 
—

 
—

 
(4
)
 
335

Rate-regulated electric revenues
—

 
4,508

 
1,893

 
1,850

 
3,549

 
—

 
(34
)
 
11,766

Rate-regulated natural gas revenues
—

 
—

 
382

 
519

 
129

 
—

 
(13
)
 
1,017

Shared service and other revenues
—

 
—

 
—

 
—

 
10

 
1,398

 
(1,408
)
 
—

Total operating revenues
$
15,368

 
$
4,508

 
$
2,275

 
$
2,369

 
$
3,688

 
$
1,398

 
$
(2,436
)
 
$
27,170

Shared service and other revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Intersegment revenues(d):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
844

 
$
13

 
$
4

 
$
18

 
$
11

 
$
1,410

 
$
(2,300
)
 
$
—

2018
981

 
23

 
5

 
18

 
11

 
1,392

 
(2,430
)
 
—

Depreciation and amortization:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
1,221

 
$
767

 
$
247

 
$
368

 
$
562

 
$
72

 
$
—

 
$
3,237

2018
1,383

 
696

 
224

 
358

 
555

 
68

 
—

 
3,284

Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
13,333

 
$
3,431

 
$
1,783

 
$
1,936

 
$
3,106

 
$
1,405

 
$
(2,291
)
 
$
22,703

2018
14,475

 
3,610

 
1,853

 
2,005

 
3,165

 
1,395

 
(2,467
)
 
24,036

Interest expense, net:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
336

 
$
268

 
$
100

 
$
89

 
$
197

 
$
231

 
$
—

 
$
1,221

2018
305

 
261

 
96

 
78

 
193

 
205

 
—

 
1,138


128
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 18 — Segment Information

 
Generation(a)
 
ComEd
 
PECO
 
BGE
 
PHI
 
Other(b)
 
Intersegment
Eliminations
 
Exelon
Income (loss) before income taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
1,355

 
$
674

 
$
461

 
$
320

 
$
436

 
$
(218
)
 
$
—

 
$
3,028

2018
800

 
663

 
331

 
301

 
363

 
(195
)
 
—

 
2,263

Income Taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
388

 
$
130

 
$
51

 
$
59

 
$
25

 
$
(27
)
 
$
—

 
$
626

2018
110

 
140

 
(5
)
 
59

 
28

 
(70
)
 
—

 
262

Net income (loss):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
784

 
$
544

 
$
410

 
$
261

 
$
412

 
$
(191
)
 
$
—

 
$
2,220

2018
667

 
523

 
336

 
242

 
336

 
(125
)
 
—

 
1,979

Capital Expenditures
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2019
$
1,282

 
$
1,413

 
$
675

 
$
842

 
$
1,006

 
$
41

 
$
—

 
$
5,259

2018
1,660

 
1,540

 
615

 
667

 
988

 
27

 
—

 
5,497

Total assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
September 30, 2019
$
47,984

 
$
32,326

 
$
11,379

 
$
10,304

 
$
22,576

 
$
8,254

 
$
(10,085
)
 
$
122,738

December 31, 2018
47,556

 
31,213

 
10,642

 
9,716

 
21,984

 
8,355

 
(9,800
)
 
119,666

__________
(a)
Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $123 million, sales to BGE of $199 million, sales to Pepco of $188 million, sales to DPL of $50 million and sales to ACE of $16 million in the Mid-Atlantic region, and sales to ComEd of $266 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $97 million, sales to BGE of $198 million, sales to Pepco of $143 million, sales to DPL of $103 million and sales to ACE of $21 million in the Mid-Atlantic region, and sales to ComEd of $419 million in the Midwest region, which eliminate upon consolidation.
(b)
Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(c)
Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(d)
Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

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

Note 18 — Segment Information

PHI:
 
Pepco
 
DPL
 
ACE
 
Other(b)
 
Intersegment
Eliminations
 
PHI
Operating revenues(a):
 
 
 
 
 
 
 
 
 
 
 
2019
 
 
 
 
 
 
 
 
 
 
 
Rate-regulated electric revenues
$
1,748

 
$
871

 
$
966

 
$
(1
)
 
$
(10
)
 
$
3,574

Rate-regulated natural gas revenues
—

 
116

 
—

 
—

 
—

 
116

Shared service and other revenues
—

 
—

 
—

 
298

 
(288
)
 
10

Total operating revenues
$
1,748

 
$
987

 
$
966

 
$
297

 
$
(298
)
 
$
3,700

2018
 
 
 
 
 
 
 
 
 
 
 
Rate-regulated electric revenues
$
1,708

 
$
872

 
$
981

 
$
—

 
$
(12
)
 
$
3,549

Rate-regulated natural gas revenues
—

 
129

 
—

 
—

 
—

 
129

Shared service and other revenues
—

 
—

 
—

 
326

 
(316
)
 
10

Total operating revenues
$
1,708

 
$
1,001

 
$
981

 
$
326

 
$
(328
)
 
$
3,688

Intersegment revenues:
 
 
 
 
 
 
 
 
 
 
 
2019
$
5

 
$
5

 
$
2

 
$
297

 
$
(298
)
 
$
11

2018
5

 
6

 
2

 
325

 
(327
)
 
11

Depreciation and amortization:
 
 
 
 
 
 
 
 
 
 
 
2019
$
281

 
$
138

 
$
114

 
$
29

 
$
—

 
$
562

2018
286

 
135

 
107

 
27

 
—

 
555

Operating expenses:
 
 
 
 
 
 
 
 
 
 
 
2019
$
1,444

 
$
820

 
$
838

 
$
302

 
$
(298
)
 
$
3,106

2018
1,454

 
859

 
847

 
329

 
(324
)
 
3,165

Interest expense, net:
 
 
 
 
 
 
 
 
 
 
 
2019
$
100

 
$
45

 
$
44

 
$
8

 
$
—

 
$
197

2018
96

 
42

 
48

 
7

 
—

 
193

Income (loss) before income taxes:
 
 
 
 
 
 
 
 
 
 
 
2019
$
226

 
$
132

 
$
89

 
$
411

 
$
(422
)
 
$
436

2018
181

 
107

 
88

 
326

 
(339
)
 
363

Income Taxes:
 
 
 
 
 
 
 
 
 
 
 
2019
$
9

 
$
16

 
$
2

 
$
(1
)
 
$
(1
)
 
$
25

2018
7

 
17

 
12

 
(8
)
 
—

 
28

Net income (loss):
 
 
 
 
 
 
 
 
 
 
 
2019
$
217

 
$
116

 
$
87

 
$
(19
)
 
$
11

 
$
412

2018
174

 
90

 
76

 
(15
)
 
11

 
336

Capital Expenditures
 
 
 
 
 
 
 
 
 
 
 
2019
$
455

 
$
245

 
$
300

 
$
6

 
$
—

 
$
1,006

2018
475

 
254

 
247

 
12

 
—

 
988

Total assets:
 
 
 
 
 
 
 
 
 
 
 
September 30, 2019
$
8,603

 
$
4,724

 
$
3,916

 
$
11,071

 
$
(5,738
)
 
$
22,576

December 31, 2018
8,299

 
4,588

 
3,699

 
10,819

 
(5,421
)
 
21,984



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

Note 18 — Segment Information

__________
(a)
Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(b)
Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
 
Nine Months Ended September 30, 2019
 
Revenues from external customers(a)
 
Intersegment
Revenues
 
Total
Revenues
 
Contracts with customers
 
Other(b)
 
Total
 
 
Mid-Atlantic
$
3,798

 
$
9

 
$
3,807

 
$
2

 
$
3,809

Midwest
3,083

 
172

 
3,255

 
(31
)
 
3,224

New York
1,195

 
16

 
1,211

 
—

 
1,211

ERCOT
594

 
198

 
792

 
13

 
805

Other Power Regions
2,849

 
451

 
3,300

 
(46
)
 
3,254

Total Competitive Businesses Electric Revenues
11,519

 
846

 
12,365

 
(62
)
 
12,303

Competitive Businesses Natural Gas Revenues
1,041

 
438

 
1,479

 
62

 
1,541

Competitive Businesses Other Revenues(c)
343

 
93

 
436

 
—

 
436

Total Generation Consolidated Operating Revenues
$
12,903

 
$
1,377

 
$
14,280

 
$
—

 
$
14,280


 
Nine Months Ended September 30, 2018
 
Revenues from external customers(a)
 
Intersegment
revenues
 
Total
Revenues
 
Contracts with customers
 
Other(b)
 
Total
 
 
Mid-Atlantic
$
3,971

 
$
191

 
$
4,162

 
$
17

 
$
4,179

Midwest
3,432

 
169

 
3,601

 
(8
)
 
3,593

New York
1,305

 
(37
)
 
1,268

 
1

 
1,269

ERCOT
470

 
459

 
929

 
1

 
930

Other Power Regions
2,656

 
574

 
3,230

 
(116
)
 
3,114

Total Competitive Businesses Electric Revenues
11,834

 
1,356

 
13,190

 
(105
)
 
13,085

Competitive Businesses Natural Gas Revenues
1,016

 
823

 
1,839

 
105

 
1,944

Competitive Businesses Other Revenues(c)
385

 
(46
)
 
339

 
—

 
339

Total Generation Consolidated Operating Revenues
$
13,235

 
$
2,133

 
$
15,368

 
$
—

 
$
15,368

__________
(a)
Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)
Includes revenues from derivatives and leases.
(c)
Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $64 million and losses of $96 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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

Note 18 — Segment Information

Revenues net of purchased power and fuel expense (Generation):
 
Nine Months Ended September 30, 2019
 
Nine Months Ended September 30, 2018
 
RNF
from external
customers(a)
 
Intersegment
RNF
 
Total RNF
 
RNF
from external
customers(a)
 
Intersegment
RNF
 
Total RNF
Mid-Atlantic
$
2,007

 
$
16

 
$
2,023

 
$
2,303

 
$
45

 
$
2,348

Midwest
2,269

 
(22
)
 
2,247

 
2,381

 
19

 
2,400

New York
800

 
10

 
810

 
832

 
9

 
841

ERCOT
252

 
(27
)
 
225

 
396

 
(180
)
 
216

Other Power Regions
542

 
(64
)
 
478

 
740

 
(133
)
 
607

Total Revenues net of purchased power and fuel expense for Reportable Segments
5,870


(87
)

5,783


6,652


(240
)

6,412

Other(b)
262

 
87

 
349

 
164

 
240

 
404

Total Generation Revenues net of purchased power and fuel expense
$
6,132


$
—


$
6,132


$
6,816


$
—


$
6,816

__________
(a)
Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)
Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $84 million and $104 million in 2019 and 2018, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of $13 million and $53 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

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

Note 18 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):
 
Nine Months Ended September 30, 2019
Revenues from contracts with customers
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Rate-regulated electric revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
2,221

 
$
1,231

 
$
1,019

 
$
1,816

 
$
792

 
$
499

 
$
525

Small commercial & industrial
1,103

 
304

 
193

 
387

 
114

 
141

 
132

Large commercial & industrial
399

 
163

 
335

 
843

 
633

 
75

 
135

Public authorities & electric railroads
35

 
23

 
20

 
47

 
27

 
10

 
10

Other(a)
660

 
186

 
242

 
481

 
166

 
151

 
164

Total rate-regulated electric revenues(b)
4,418

 
1,907

 
1,809

 
3,574

 
1,732

 
876

 
966

Rate-regulated natural gas revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
—

 
285

 
327

 
64

 
—

 
64

 
—

Small commercial & industrial
—

 
122

 
55

 
30

 
—

 
30

 
—

Large commercial & industrial
—

 
1

 
93

 
4

 
—

 
4

 
—

Transportation
—

 
18

 
—

 
11

 
—

 
11

 
—

Other(c)
—

 
5

 
19

 
6

 
—

 
6

 
—

Total rate-regulated natural gas revenues(d)
—

 
431

 
494

 
115

 
—

 
115

 
—

Total rate-regulated revenues from contracts with customers
4,418

 
2,338

 
2,303

 
3,689

 
1,732

 
991

 
966

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from alternative revenue programs
(98
)
 
(16
)
 
11

 
4

 
10

 
(6
)
 
—

Other rate-regulated electric revenues(e)
22

 
10

 
10

 
7

 
6

 
1

 
—

Other rate-regulated natural gas revenues(e)
—

 
1

 
3

 
—

 
—

 
1

 
—

Total other revenues
(76
)
 
(5
)
 
24

 
11

 
16

 
(4
)
 
—

Total rate-regulated revenues for reportable segments
$
4,342

 
$
2,333

 
$
2,327

 
$
3,700

 
$
1,748

 
$
987

 
$
966


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

Note 18 — Segment Information

 
Nine Months Ended September 30, 2018
Revenues from contracts with customers
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Rate-regulated electric revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
$
2,277

 
$
1,199

 
$
1,054

 
$
1,839

 
$
792

 
$
513

 
$
534

Small commercial & industrial
1,132

 
306

 
196

 
370

 
104

 
138

 
128

Large commercial & industrial
411

 
174

 
325

 
845

 
632

 
74

 
139

Public authorities & electric railroads
36

 
21

 
21

 
44

 
24

 
10

 
10

Other(a)
656

 
181

 
246

 
446

 
145

 
129

 
174

Total rate-regulated electric revenues(b)
4,512

 
1,881

 
1,842

 
3,544

 
1,697

 
864

 
985

Rate-regulated natural gas revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Residential
—

 
259

 
345

 
68

 
—

 
68

 
—

Small commercial & industrial
—

 
102

 
55

 
31

 
—

 
31

 
—

Large commercial & industrial
—

 
1

 
88

 
7

 
—

 
7

 
—

Transportation
—

 
16

 
—

 
12

 
—

 
12

 
—

Other(c)
—

 
4

 
49

 
11

 
—

 
11

 
—

Total rate-regulated natural gas revenues(d)
—

 
382

 
537

 
129

 
—

 
129

 
—

Total rate-regulated revenues from contracts with customers
4,512

 
2,263

 
2,379

 
3,673

 
1,697

 
993

 
985

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other revenues
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues from alternative revenue programs
(27
)
 
2

 
(23
)
 
7

 
6

 
5

 
(4
)
Other rate-regulated electric revenues(e)
23

 
10

 
10

 
8

 
5

 
3

 
—

Other rate-regulated natural gas revenues(e)
—

 
—

 
3

 
—

 
—

 
—

 
—

Total other revenues
(4
)
 
12

 
(10
)
 
15

 
11

 
8

 
(4
)
Total rate-regulated revenues for reportable segments
$
4,508

 
$
2,275

 
$
2,369

 
$
3,688

 
$
1,708

 
$
1,001

 
$
981


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


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

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Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the three and nine months ended September 30, 2019 compared to the same period in 2018. For additional information regarding the financial results for the three and nine months ended September 30, 2019 and 2018 see the discussions of Results of Operations by Registrant.
 
Three Months Ended September 30,
 
Favorable (unfavorable) variance
 
Nine Months Ended September 30,
 
Favorable (unfavorable) variance
 
2019
 
2018
 
 
2019
 
2018
 
Exelon
772

 
733

 
$
39

 
$
2,164

 
$
1,858

 
$
306

Generation
257

 
234

 
23

 
728

 
547

 
181

ComEd
200

 
193

 
7

 
544

 
523

 
21

PECO
140

 
126

 
14

 
410

 
336

 
74

BGE
55

 
63

 
(8
)
 
261

 
242

 
19

PHI
189

 
187

 
2

 
412

 
336

 
76

Pepco
98

 
89

 
9

 
217

 
174

 
43

DPL
33

 
33

 
—

 
116

 
90

 
26

ACE
63

 
61

 
2

 
87

 
76

 
11

Other(a)
(69
)
 
(70
)
 
1

 
(191
)
 
(126
)
 
(65
)
__________
(a)
Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities.
Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018. Net income attributable to common shareholders increased by $39 million and diluted earnings per average common share increased to $0.79 in 2019 from $0.76 in 2018 primarily due to:
•
Absence of accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO;
•
Decreased nuclear outage days in 2019;
•
Increased New York ZEC prices and the approval of the New Jersey ZEC program in the second quarter of 2019;
•
A benefit associated with the annual nuclear ARO update;
•
Decreased Operating and maintenance expense, which includes the impacts of previous cost management programs and lower pension and OPEB costs; and
•
Regulatory rate increases at PECO, BGE, Pepco, DPL and ACE.
The increases were partially offset by:
•
Lower capacity prices;
•
Lower mark-to-market gains;
•
Lower realized energy prices; and
•
Unfavorable weather conditions and volume at PECO.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018. Net income attributable to common shareholders increased by $306 million and diluted earnings per average common share increased to $2.22 in 2019 from $1.92 in 2018 primarily due to:

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•
Higher net unrealized and realized gains on NDT funds;
•
Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO;
•
Decreased Operating and maintenance expense which includes the impacts of previous cost management programs and lower pension and OPEB costs;
•
Decreased nuclear outage days in 2019;
•
A benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019 and the annual nuclear ARO update in the third quarter of 2019;
•
Regulatory rate increases at PECO, BGE, Pepco, DPL, and ACE; and
•
Decreased storms costs at PECO and BGE.
The increases were partially offset by:
•
Lower realized energy prices;
•
Lower capacity prices;
•
The absence of the revenues recognized in the first quarter of 2018 related to ZECs generated in Illinois from June through December 2017, partially offset by increased New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019;
•
Higher mark-to-market losses; and
•
Unfavorable weather conditions and volume at PECO.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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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 nine months ended September 30, 2019 compared to the same period in 2018.
 
Three Months Ended September 30,
 
2019
 
2018
(All amounts in millions after tax)
 
 
Earnings per
Diluted Share
 
 
 
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders
$
772

 
$
0.79

 
$
733

 
$
0.76

Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $2 and $20, respectively)
(2
)
 
—

 
(55
)
 
(0.06
)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $34 and $4, respectively)(a)
(39
)
 
(0.04
)
 
(53
)
 
(0.06
)
Asset Impairments (net of taxes of $53 and $2, respectively)(b)
113

 
0.12

 
6

 
0.01

Plant Retirements and Divestitures (net of taxes of $40 and $70, respectively)(c)
119

 
0.12

 
202

 
0.21

Cost Management Program (net of taxes of $3 and $4, respectively)(d)
14

 
0.01

 
13

 
0.01

Asset Retirement Obligation(e) (net of taxes of $9 and $6, respectively)
(84
)
 
(0.09
)
 
16

 
0.02

Change in Environmental Liabilities (net of taxes of $5 and $3, respectively)
18

 
0.02

 
(9
)
 
(0.01
)
Income Tax-Related Adjustments (entire amount represents tax expense)(f)
13

 
0.01

 
(18
)
 
(0.02
)
Noncontrolling Interests (net of taxes of $3 and $4, respectively)(g)
(24
)
 
(0.02
)
 
21

 
0.02

Adjusted (non-GAAP) Operating Earnings
$
900

 
$
0.92

 
$
856

 
$
0.88


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Nine Months Ended September 30,
 
2019
 
2018
(All amounts in millions after tax)
 
 
Earnings per
Diluted Share
 
 
 
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders
$
2,164

 
$
2.22

 
$
1,858

 
$
1.92

Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $31 and $26, respectively)
97

 
0.10

 
74

 
0.08

Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $167 and $118, respectively)(a)
(181
)
 
(0.19
)
 
94

 
0.10

PHI Merger and Integration Costs (net of taxes of $1)
—

 
—

 
5

 
—

Asset Impairments (net of taxes of $54 and $13, respectively)(b)
119

 
0.12

 
36

 
0.04

Plant Retirements and Divestitures (net of taxes of $9 and $148, respectively)(c)
114

 
0.12

 
422

 
0.43

Cost Management Program (net of taxes of $10 and $10, respectively)(d)
31

 
0.03

 
29

 
0.03

Litigation Settlement Gain (net of taxes of $7)
(19
)
 
(0.02
)
 
—

 
—

Asset Retirement Obligation (net of taxes of $9 and $6, respectively)(e)
(84
)
 
(0.09
)
 
16

 
0.02

Change in Environmental Liabilities (net of taxes of $5 and $1, respectively)
18

 
0.02

 
(4
)
 
—

Income Tax-Related Adjustments (entire amount represents tax expense)(f)
13

 
0.01

 
(27
)
 
(0.03
)
Noncontrolling Interests (net of taxes of $18 and $9, respectively)(g)
58

 
0.06

 
(36
)
 
(0.04
)
Adjusted (non-GAAP) Operating Earnings
$
2,329

 
$
2.39

 
$
2,467

 
$
2.55

__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2019 and 2018 ranged from 26.0 percent to 29.0 percent. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 47.1 percent and 7.7 percent for the three months ended September 30, 2019 and 2018, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 48.1 percent and 55.5 percent for the nine months ended September 30, 2019 and 2018, respectively.

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

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

$
25

N/A

December 20, 2018
January 1, 2019
BGE - Maryland (Natural Gas)
June 8, 2018 (amended October 12, 2018)
$
61

$
43

9.8
%
January 4, 2019
January 4, 2019
ACE - New Jersey (Electric)
August 21, 2018 (amended November 19, 2018)
$
122

$
70

9.6
%
March 13, 2019
April 1, 2019
Pepco - Maryland (Electric)
January 15, 2019 (amended May 16, 2019)
$
27

$
10

9.6
%
August 12, 2019
August 13, 2019

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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 8, 2019
$
(6
)
8.91
%
December 2019
BGE - Maryland (Electric)(a)
May 24, 2019 (amended October 4, 2019)
$
74

10.3
%
December 2019
BGE - Maryland (Natural Gas)(a)
May 24, 2019 (amended October 4, 2019)
$
59

10.3
%
December 2019
Pepco - District of Columbia (Electric)
May 30, 2019 (amended September 16, 2019)
$
160

10.3
%
Fourth quarter of 2020
__________
(a)
On October 25, 2019, BGE filed a settlement agreement with the MDPSC. The settlement provides for an increase to BGE’s annual electric and natural gas distribution rates of $18 million and $45 million, respectively.
Transmission Formula Rate
The following total increases/(decreases) were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2019 annual electric transmission formula rate updates.
Registrant
Initial Revenue Requirement Increase (Decrease)
Annual Reconciliation Increase (Decrease)
Total Revenue Requirement Increase (Decrease)
Allowed Return on Rate Base
Allowed ROE
ComEd
21

(16
)
5

8.21
%
11.50
%
BGE
(10
)
(23
)
(19
)
7.35
%
10.50
%
Pepco
15

11

26

7.75
%
10.50
%
DPL
17

(1
)
16

7.14
%
10.50
%
ACE
11

(2
)
9

7.79
%
10.50
%
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. PECO’s initial formula rate filing included a requested increase of  $22 million to PECO’s annual transmission revenue requirement, which reflected a ROE of  11%, inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures.
Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.
On July 22, 2019, PECO and other parties filed with FERC a settlement agreement, which includes a ROE of 10.35%, inclusive of a 50 basis point adder for being a member of a RTO. The settlement did not have a material impact on PECO’s 2017, 2018, or 2019 annual transmission revenue requirements. A final order from FERC is expected before the end of the first quarter of 2020. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.

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Early Plant Retirements and Divestitures
Oyster Creek. Generation permanently ceased generation operations at Oyster Creek on September 17, 2018. On July 31, 2018, Generation entered into an agreement with Holtec International and its wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the sale and decommissioning of Oyster Creek. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter 2019, which was immaterial. See Note 3 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Three Mile Island. Generation permanently ceased operations at TMI on September 20, 2019. As a result of the decision to early retire TMI, Exelon and Generation recorded a $113 million and $185 million incremental pre-tax net charge for the three and nine months ended September 30, 2019 primarily due to accelerated depreciation of the plant assets, partially offset by a benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019.
Salem. In 2017, PSEG announced that its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest, were showing increased signs of economic distress, which could lead to an early retirement. PSEG is the operator of Salem and also has the decision-making authority to retire Salem. In 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Assuming the continued effectiveness of the New Jersey ZEC program, Generation no longer considers Salem to be at heightened risk for early retirement.
Dresden, Byron and Braidwood. Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.
See Note 6 — Regulatory Matters, Note 8 — Early Plant Retirements and Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.
Pacific Gas & Electric Bankruptcy
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code. As of September 30, 2019, Generation had approximately $730 million and $495 million of net long-lived assets and nonrecourse debt outstanding, respectively, related to Antelope Valley. PG&E’s bankruptcy created an event of default for Antelope Valley’s nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the ongoing event of default and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of September 30, 2019.
In the first quarter of 2019, Generation assessed and determined that Antelope Valley’s long-lived assets were not impaired. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley's net long-lived assets, which could be material. Generation is monitoring the bankruptcy proceedings for any changes in circumstances that would indicate the carrying amount of the net long-lived assets of Antelope Valley may not be recoverable.
See Note 7 — Asset Impairments and Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the PG&E bankruptcy.

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Other Key Business Drivers and Management Strategies
The following discussion of other key business driver and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Key Business Drivers and Management Strategies in the Registrants' combined 2018 Form 10-K and Note 16 - Commitments and Contingencies to the Consolidated Financial Statements in this report for additional information on various environmental matters.
Power Markets
Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs
PJM and NYISO capacity markets include a MOPR that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new gas-fired resources.
On January 9, 2017, EPSA filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. A similar complaint also against PJM was filed at FERC on May 31, 2018. These complaints generally allege that the relevant MOPR should be expanded to also apply to existing resources including those receiving ZEC compensation under the New Jersey ZEC, New York CES and Illinois ZES programs. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute and are no different than other renewable support programs that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions, which could have a material effect on Exelon’s and Generation’s future cash flows and results of operations.
In June 2018, FERC addressed one of the MOPR complaints involving PJM and concluded that PJM’s existing tariff allows resources receiving out-of-market support to affect capacity prices in a manner that will cause unjust and unreasonable and unduly discriminatory rates in PJM. FERC suggested that modifying two elements of PJM’s existing tariff, as follows could produce a just and reasonable replacement.
•
An expansion of the current MOPR mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or REC compensation, could protect the capacity markets from unwanted price suppression.
•
A modified version of PJM’s existing Fixed Resource Requirement (FRR) option could enable state subsidized resources and a corresponding amount of load to be removed from the capacity market, thereby alleviating their price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through mechanisms other than through PJM’s existing market mechanism.
FERC established March 21, 2016 as the refund effective date and also allowed PJM to delay its next capacity auction from May 2019 to August 2019 to allow parties time to file proposals in the FERC proceeding, FERC time to determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates, environmental organizations and other nuclear generators, submitted shared principles supporting a workable new FRR mechanism. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. On April 10, 2019, PJM notified FERC of its intent to proceed with the next capacity auction in August 2019 under the existing market rules and asked FERC to clarify that it would not require PJM to re-run the auction in the event FERC alters those market rules in its decision on the MOPR complaint. On July 25, 2019, FERC issued an order denying PJM’s request to clarify that any alteration of PJM’s existing market rules would operate prospectively and, therefore, directed PJM to not conduct the capacity auction in August 2019. It is too early to predict the final outcome of each of these proceedings or their potential financial impact, if any, on Exelon or Generation.

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Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps
On February 21, 2019, PJM’s Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM claims that this allows for the exercise of market power. The IMM asks FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation.
Section 232 Uranium Petition
On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce (DOC) seeking relief under Section 232 of the Trade Expansion Act of 1962, as amended, (the Act) from imports of uranium products, alleging that these imports threaten national security (the Petition). The relief requested would have required U.S. nuclear reactors to purchase at least 25% of their uranium needs from domestic mines for the next 10 years or more. The Act was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.
On July 18, 2018, the Secretary announced that the DOC had initiated an investigation in response to the petition. The Secretary submitted a report to President Trump on April 14, 2019 that has not been made public. On July 12, 2019, the President issued a memorandum indicating that he did not agree with the Secretary’s finding that uranium imports threaten to impair the national security of the United States, choosing not to impose any trade restrictions at this time. The President found that a fuller analysis of national security considerations with respect to the entire nuclear fuel supply chain is necessary and directed that a United States Nuclear Fuel Working Group (Working Group) be established to develop recommendations for reviving and expanding domestic nuclear fuel production with a mandate to submit a report back to him within 90 days. On October 10, 2019, the President granted a 30-day extension to the deadline for the Working Group to submit the report. The Working Group is to be co-chaired by the Assistant to the President for National Security Affairs and the Assistant to the President for Economic Policy. Exelon will monitor and volunteer to provide information to support the Working Group’s efforts. Exelon and Generation cannot currently predict the outcome of the Working Group report and subsequent actions.
Hedging Strategy
Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. As of September 30, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 96%-99%, 84%-87% and 54%-57% for 2019, 2020, and 2021 respectively. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.
Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 63% of Generation’s uranium concentrate requirements from 2019 through 2023 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s financial statements.

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See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and Item 3. Quantitative and Qualitative Disclosures about Market Risk for additional information.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Environmental Legislative and Regulatory Developments
Air Quality
Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. In June 2019, EPA issued a final rule that repealed the CPP, and finalized the Affordable Clean Energy rule to replace the CPP with less stringent emissions guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants.
Primary SO2 National Ambient Air Quality Standards (NAAQS). EPA took final action on April 17, 2019 to retain the current primary SO2 standard without revision, leaving the standard established in 2010 in effect.
See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to environmental matters, including the impact of environmental regulation.
Other Legislative and Regulatory Developments
Illinois Clean Energy Progress Act
On March 14, 2019, the Clean Energy Progress Act was introduced in the Illinois General Assembly to preserve Illinois’ clean energy choices arising from FEJA and empower the IPA to conduct capacity procurements outside of PJM’s base residual auction process, while utilizing the fixed resource requirement provisions in PJM's tariffs which are still subject to penalties and other obligations under the PJM tariffs. The most significant provisions of the proposed legislation are as follows: (1) it allows the IPA to procure capacity directly from clean energy resources that have previously sold ZECs or RECs, including certain of Generation’s nuclear plants in Illinois, or from new clean energy resources, (2) it establishes a goal of achieving 100% carbon-free power in the ComEd service territory by 2032, and (3) it implements reforms to enhance consumer protections in the state’s competitive retail electricity and natural gas markets, including Generation’s retail customers. Energy legislation has also been proposed by other stakeholders, including renewable resource developers, environmental advocates, and coal-fueled generators. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Keep Powering Pennsylvania Act
On March 11, 2019, the Keep Powering Pennsylvania Act was introduced in the Pennsylvania General Assembly to amend the Alternative Energy Portfolio Standards Act of 2004. The proposed legislation recognizes the value that all zero-emission electric generation resources provide to Pennsylvania by adding nuclear plants and certain other renewable generation resources (Tier III resources) to the zero-emission electric generation resources that currently receive alternative energy credits in Pennsylvania. Further, the proposed legislation would allow for these Tier III resources to continue to receive capacity payments at the same level as the PJM capacity auction clearing price. In order to initially qualify as a Tier III resource, a resource must make a commitment to operate for at least six years. The price of the alternative energy credits for Tier III resources is tied to the value of existing Tier I resources, with a price cap. Regulated utilities, including PECO, would be required to purchase alternative energy credits for all retail customers and allowed to recover those costs from customers. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Nuclear Powers Act of 2019
On April 12, 2019, the Nuclear Powers America Act of 2019 was introduced to the United States Congress, which expands the current investment tax credit to existing nuclear power plants. The proposed legislation would provide

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a credit equal to 30% of continued capital investment in certain nuclear energy-related expenditures, including capital expenses and nuclear fuel, starting from tax years 2019 through 2023. Thereafter, the credit rate would be reduced to 26% in 2024, 22% in 2025, and 10% in 2026 and beyond. To qualify for the credit, the plant must be currently operational and must have applied for an operating license renewal before 2026.  Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.
Employees
In April 2019, the CBAs with IBEW Local 15 covering employees at BSC, ComEd and Generation, were extended through 2024. In June 2019, BGE’s union contract for approximately 1,400 employees within Local 410 was ratified, which did not have a material impact on BGE's financial statements. In July 2019, the CBA between Generation and the Security Officer’s union at Byron, which was scheduled to expire on September 30, 2019, was extended to December 31, 2019. In September 2019, negotiations completed between Pepco and IBEW Local 1900 and the CBA will expire in 2022. In September 2019, the CBA between Generation and Local 614 at Conowingo, Eddystone and Fairless Hills stations, which was scheduled to expire on November 3, 2019, was extended to March 3, 2020.
Critical Accounting Policies and Estimates
Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. At September 30, 2019, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2018. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the Registrants' 2018 Form 10-K for further information.
Results of Operations by Registrant
The Registrants' Results of Operations includes discussion of RNF, which is a financial measure not defined under GAAP and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. The CODMs for Exelon and Generation evaluate the performance of Generation's electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measure because it provides information that can be used to evaluate its operational performance. For the Utility Registrants, their Operating revenues reflect the full and current recovery of commodity procurement costs given the rider mechanisms approved by their respective state regulators. The commodity procurement costs, which are recorded in Purchased power and fuel expense, and the associated revenues can be volatile. Therefore, the Utility Registrants believe that RNF is a useful measure because it excludes the effect on Operating revenues caused by the volatility in these expenses.

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Results of Operations — Generation
 
Three Months Ended
September 30,
 
Favorable
(Unfavorable)
Variance
 
Nine Months Ended
September 30,
 
Favorable
(Unfavorable)
Variance
 
2019
 
2018
 
 
2019
 
2018
 
Operating revenues
$
4,774

 
$
5,278

 
$
(504
)
 
$
14,280

 
$
15,368

 
$
(1,088
)
Purchased power and fuel expense
2,651

 
2,980

 
329

 
8,148

 
8,552

 
404

Revenues net of purchased power and fuel expense
2,123

 
2,298

 
(175
)
 
6,132

 
6,816

 
(684
)
Other operating expenses
 
 
 
 
 
 
 
 
 
 
 
Operating and maintenance
1,087

 
1,370

 
283

 
3,570

 
4,126

 
556

Depreciation and amortization
407

 
468

 
61

 
1,221

 
1,383

 
162

Taxes other than income
129

 
143

 
14

 
394

 
414

 
20

Total other operating expenses
1,623

 
1,981

 
358

 
5,185

 
5,923

 
738

(Loss) gain on sales of assets and businesses
(18
)
 
(6
)
 
(12
)
 
15

 
48

 
(33
)
Operating income
482


311

 
171

 
962


941

 
21

Other income and (deductions)
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(109
)
 
(101
)
 
(8
)
 
(336
)
 
(305
)
 
(31
)
Other, net
128

 
179

 
(51
)
 
729

 
164

 
565

Total other income and (deductions)
19

 
78

 
(59
)
 
393

 
(141
)
 
534

Income before income taxes
501

 
389

 
112

 
1,355

 
800

 
555

Income taxes
87

 
78

 
(9
)
 
388

 
110

 
(278
)
Equity in losses of unconsolidated affiliates
(170
)
 
(11
)
 
(159
)
 
(183
)
 
(23
)
 
(160
)
Net income
244


300


(56
)

784


667


117

Net (loss) income attributable to noncontrolling interests
(13
)
 
66

 
79

 
56

 
120

 
64

Net income attributable to membership interest
$
257

 
$
234

 
$
23

 
$
728

 
$
547

 
$
181

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018. Net income attributable to membership interest increased by $23 million primarily due to:
•
Absence of accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO;
•
Decreased nuclear outage days in 2019;
•
Increased New York ZEC prices and the approval of the New Jersey ZEC program in the second quarter of 2019;
•
A benefit associated with the annual nuclear ARO update; and
•
Decreased Operating and maintenance expense, which includes the impacts of previous cost management programs and lower pension and OPEB costs.
The increases were partially offset by:
•
Lower capacity prices;

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

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For the three and nine months ended September 30, 2019 and 2018, RNF by region were as follows:
 
Three Months Ended
September 30,
 
Variance
 
% Change
 
Nine Months Ended
September 30,
 
Variance
 
% Change
 
2019
 
2018
 
 
2019
 
2018
 
Mid-Atlantic(a)
$
689

 
$
763

 
$
(74
)
 
(9.7
)%
 
$
2,023

 
$
2,348

 
$
(325
)
 
(13.8
)%
Midwest(b)
747

 
768

 
(21
)
 
(2.7
)%
 
2,247

 
2,400

 
(153
)
 
(6.4
)%
New York
291

 
292

 
(1
)
 
(0.3
)%
 
810

 
841

 
(31
)
 
(3.7
)%
ERCOT
72

 
98

 
(26
)
 
(26.5
)%
 
225

 
216

 
9

 
4.2
 %
Other Power Regions
184

 
180

 
4

 
2.2
 %
 
478

 
607

 
(129
)
 
(21.3
)%
Total electric revenue net of purchased power and fuel expense
1,983

 
2,101

 
(118
)
 
(5.6
)%
 
5,783

 
6,412

 
(629
)
 
(9.8
)%
Proprietary Trading
(1
)
 
5

 
(6
)
 
(120.0
)%
 
10

 
39

 
(29
)
 
(74.4
)%
Mark-to-market gains (losses)
17

 
71

 
(54
)
 
(76.1
)%
 
(84
)
 
(104
)
 
20

 
(19.2
)%
Other
124

 
121

 
3

 
2.5
 %
 
423

 
469

 
(46
)
 
(9.8
)%
Total revenue net of purchased power and fuel expense
$
2,123

 
$
2,298

 
$
(175
)
 
(7.6
)%
 
$
6,132

 
$
6,816

 
$
(684
)
 
(10.0
)%
_________
(a)
Includes results of transactions with PECO, BGE, Pepco, DPL and ACE.
(b)
Includes results of transactions with ComEd.

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Generation’s supply sources by region are summarized below:
 
Three Months Ended
September 30,
 
Variance
 
% Change
 
Nine Months Ended
September 30,
 
Variance
 
% Change
Supply source (GWhs)
2019
 
2018
 
 
2019
 
2018
 
Nuclear Generation(a)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Mid-Atlantic
15,281

 
16,197

 
(916
)
 
(5.7
)%
 
44,436

 
48,924

 
(4,488
)
 
(9.2
)%
Midwest
23,730

 
23,834

 
(104
)
 
(0.4
)%
 
71,459

 
70,532

 
927

 
1.3
 %
New York
7,204

 
6,518

 
686

 
10.5
 %
 
20,783

 
19,758

 
1,025

 
5.2
 %
Total Nuclear Generation
46,215

 
46,549

 
(334
)
 
(0.7
)%
 
136,678


139,214

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


 


Mid-Atlantic
485

 
853

 
(368
)
 
(43.1
)%
 
2,351

 
2,660

 
(309
)
 
(11.6
)%
Midwest
262

 
244

 
18

 
7.4
 %
 
981

 
1,020

 
(39
)
 
(3.8
)%
New York
3

 
1

 
2

 
200.0
 %
 
4

 
3

 
1

 
33.3
 %
ERCOT
4,500

 
3,137

 
1,363

 
43.4
 %
 
10,644

 
8,389

 
2,255

 
26.9
 %
Other Power Regions
3,135

 
3,628

 
(493
)
 
(13.6
)%
 
8,789

 
10,692

 
(1,903
)
 
(17.8
)%
Total Fossil and Renewables
8,385

 
7,863

 
522

 
6.6
 %
 
22,769


22,764

 
5

 
—
 %
Purchased Power
 
 
 
 
 
 
 
 
 
 
 
 


 


Mid-Atlantic
5,235

 
3,504

 
1,731

 
49.4
 %
 
10,359

 
4,828

 
5,531

 
114.6
 %
Midwest
124

 
174

 
(50
)
 
(28.7
)%
 
662

 
733

 
(71
)
 
(9.7
)%
ERCOT
1,329

 
1,811

 
(482
)
 
(26.6
)%
 
3,585

 
5,504

 
(1,919
)
 
(34.9
)%
Other Power Regions
13,006

 
12,705

 
301

 
2.4
 %
 
36,693

 
32,731

 
3,962

 
12.1
 %
Total Purchased Power
19,694

 
18,194

 
1,500

 
8.2
 %
 
51,299


43,796

 
7,503

 
17.1
 %
Total Supply/Sales by Region
 
 
 
 
 
 
 
 
 
 
 
 


 


Mid-Atlantic(b)
21,001

 
20,554

 
447

 
2.2
 %
 
57,146

 
56,412

 
734

 
1.3
 %
Midwest(b)
24,116

 
24,252

 
(136
)
 
(0.6
)%
 
73,102

 
72,285

 
817

 
1.1
 %
New York
7,207

 
6,519

 
688

 
10.6
 %
 
20,787

 
19,761

 
1,026

 
5.2
 %
ERCOT
5,829

 
4,948

 
881

 
17.8
 %
 
14,229

 
13,893

 
336

 
2.4
 %
Other Power Regions
16,141

 
16,333

 
(192
)
 
(1.2
)%
 
45,482

 
43,423

 
2,059

 
4.7
 %
Total Supply/Sales by Region
74,294

 
72,606

 
1,688

 
2.3
 %
 
210,746


205,774

 
4,972

 
2.4
 %
_________
(a)
Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG).
(b)
Includes affiliate sales to PECO, BGE, Pepco, DPL and ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

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

$
(325
)
• lower realized energy prices
• decreased revenue due to permanent cease of generation operations at Oyster Creek in Q3 2018
• increased nuclear outage days primarily at Salem
• decreased capacity prices, partially offset by
• increased ZEC revenues due to the approval of the NJ ZEC program in Q2 2019
Midwest
(21
)
• decreased capacity prices partially offset by
• higher realized energy prices


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

ERCOT
(26
)
• decrease due to higher procurement costs for owned and contracted assets
9

• higher realized energy prices, partially offset by
• higher procurements costs for owned and contracted assets
Other Power Regions
4

• higher realized energy prices, partially offset by
• decreased capacity prices
(129
)
• lower realized energy prices
• decreased capacity prices
Proprietary Trading
(6
)
• congestion activity
(29
)
• congestion activity
Mark-to-market(a)
(54
)
• gains on economic hedging activities of $17 million in 2019 compared to gains of $71 million in 2018
20

• losses on economic hedging activities of $84 million in 2019 compared to losses of $104 million in 2018
Other
3

• no significant changes
(46
)
• the impacts of declining natural gas prices, partially offset by
• decrease in accelerated nuclear fuel amortization associated with announced early plant retirements
Total
$
(175
)
 
$
(684
)
 
_________
(a)
See Note 10 — Derivative Financial Instruments for additional information on mark-to-market losses.

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Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for the Generation-operated plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2019
 
2018
 
2019
 
2018
Nuclear fleet capacity factor
95.5
%
 
93.6
%
 
95.9
%
 
94.4
%
Refueling outage days
15

 
36

 
145

 
198

Non-refueling outage days
15

 
12

 
43

 
20

The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Labor, other benefits, contracting, materials(a)
$
(77
)
 
$
(135
)
Nuclear refueling outage costs, including the co-owned Salem plants
(35
)
 
(52
)
Corporate allocations
(12
)
 
(41
)
Insurance(b)
—

 
31

Merger and integration costs
—

 
(5
)
Plant retirements and divestitures(c)
(78
)
 
(164
)
Change in environmental liabilities
13

 
6

ARO update(d)
(66
)
 
(66
)
Asset Impairments(e)
(6
)
 
(38
)
Pension and non-pension postretirement benefits expense
(11
)
 
(44
)
Allowance for uncollectible accounts
(1
)
 
(18
)
Accretion expense
(11
)
 
(28
)
Other
1

 
(2
)
Decrease in Operating and maintenance expense
$
(283
)
 
$
(556
)
_________ 
(a)
Primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek, lower labor costs resulting from previous cost management programs, and lower pension and OPEB costs.
(b)
Primarily reflects the absence of a supplemental NEIL insurance distribution received in the first quarter of 2018.
(c)
Primarily due to the benefit recorded in the first quarter of 2019 for the remeasurement of the TMI ARO and the absence of a charge associated with the remeasurement of the Oyster Creek ARO in the third quarter of 2018.
(d)
Primarily reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.
(e)
Primarily due to the impairment of certain wind projects recorded in the second quarter of 2018.
Depreciation and Amortization Expense for the three and nine months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to the permanent cease of generation operations at Oyster Creek in the third quarter of 2018.
Gain (Loss) on Sales of Assets and Businesses for the three months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to Generation's sale of Oyster Creek. Gain (loss) on sales of

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Generation

assets and businesses for the nine months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to Generation's sale of its electrical contracting business in the first quarter of 2018.
Other, net for the three months ended September 30, 2019 compared to the same period in 2018 decreased and for the nine months ended September 30, 2019 compared to the same period in 2018 increased due to activity associated with NDT funds as described in the table below:
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2019
 
2018
 
2019
 
2018
Net unrealized gains (losses) on NDT funds(a)
$
55


$
72

 
$
236

 
$
(143
)
Net realized gains on sale of NDT funds(a)
9

 
29

 
231

 
164

Interest and dividend income on NDT funds(a)
24

 
29

 
85

 
93

Contractual elimination of income tax expense(b)
31

 
29

 
150

 
24

Other
9

 
20

 
27

 
26

Total other, net
$
128

 
$
179

 
$
729

 
$
164

_________ 
(a)
Unrealized gains (losses), realized gains and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement units.
(b)
Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement units.
Effective income tax rates were 17.4% and 20.1% for the three months ended September 30, 2019 and 2018, respectively. Generation's effective income tax rates were 28.6% and 13.8% for the nine months ended September 30, 2019 and 2018, respectively. The change is primarily related to a reduction in renewable tax credits and one-time tax adjustments. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Equity in losses of unconsolidated affiliates for the three and nine months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to the impairment of equity method investments in certain distributed energy companies.
Net income attributable to noncontrolling interests for the three and nine months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to the offsetting noncontrolling interest impact of the impairment of equity method investments in certain distributed energy companies.

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ComEd

Results of Operations — ComEd
 
Three Months Ended
September 30,
 
Favorable
(Unfavorable)
Variance
 
Nine Months Ended
September 30,
 
Favorable
(Unfavorable)
Variance
 
2019
 
2018
 
 
2019
 
2018
 
Operating revenues
$
1,583

 
$
1,598

 
$
(15
)
 
$
4,342

 
$
4,508

 
$
(166
)
Purchased power expense
577

 
619

 
42

 
1,469

 
1,702

 
233

Revenues net of purchased power expense
1,006

 
979

 
27

 
2,873

 
2,806

 
67

Other operating expenses
 
 
 
 
 
 
 
 
 
 
 
Operating and maintenance
340

 
337

 
(3
)
 
967

 
974

 
7

Depreciation and amortization
259

 
237

 
(22
)
 
767

 
696

 
(71
)
Taxes other than income
80

 
82

 
2

 
228

 
238

 
10

Total other operating expenses
679

 
656

 
(23
)
 
1,962

 
1,908

 
(54
)
Gain on sales of assets
1

 
—

 
1

 
4

 
5

 
(1
)
Operating income
328

 
323

 
5

 
915

 
903

 
12

Other income and (deductions)
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(91
)
 
(85
)
 
(6
)
 
(268
)
 
(261
)
 
(7
)
Other, net
8

 
7

 
1

 
27

 
21

 
6

Total other income and (deductions)
(83
)
 
(78
)
 
(5
)
 
(241
)
 
(240
)
 
(1
)
Income before income taxes
245

 
245

 
—

 
674

 
663

 
11

Income taxes
45

 
52

 
7

 
130

 
140

 
10

Net income
$
200

 
$
193

 
$
7

 
$
544

 
$
523

 
$
21

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018. Net income remained relatively consistent for the three months ended September 30, 2019 as compared to the same period in 2018.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018. Net income increased $21 million as compared to the same period in 2018, primarily due to higher electric distribution, transmission and energy efficiency formula rate earnings (reflecting the impacts of higher rate base, partially offset by lower allowed electric distribution ROE due to a decrease in treasury rates). 
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC, and ZEC procurement costs and participation in customer choice programs. ComEd recovers electricity, REC, and ZEC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries but do impact Operating revenues related to supplied electricity.

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ComEd

The changes in RNF consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Electric distribution
$
11

 
$
48

Transmission
5

 
27

Energy efficiency
9

 
36

Uncollectible accounts recovery, net
(3
)
 
(5
)
Other
5

 
(39
)
Total increase
$
27

 
$
67

Revenue Decoupling. The demand for electricity is affected by weather conditions and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer or number of customers as a result of a change to the electric distribution formula rate pursuant to FEJA.
Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased during the three and nine months ended September 30, 2019 as compared to the same period in 2018, primarily due to the impact of higher rate base and increased depreciation expenses, offset by lower allowed ROE due to a decrease in treasury rates. See Note 6 — 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 increased for the three months ended September 30, 2019 as compared to the same period in 2018, primarily due to the impact of higher rate base and higher fully recoverable costs. Transmission revenue increased for the nine months ended September 30, 2019 as compared to the same period in 2018, primarily due to the impact of increased peak load, higher rate base, and higher fully recoverable costs. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the three and nine months ended September 30, 2019 as compared to the same period in 2018, primarily due to the impact of higher rate base and increased regulatory asset amortization. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Uncollectible Accounts Recovery, Net represents recoveries under the uncollectible accounts tariff. See Operating and maintenance expense discussion below for additional information on this tariff.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of environmental costs associated with MGP sites. Other revenue remained consistent for the three months ended September 30, 2019 as compared to the same period in 2018. The decrease in Other revenue for the nine months ended September 30, 2019 as compared to the same period in 2018 primarily reflects absence of mutual assistance revenues associated with hurricane and winter storm restoration efforts that occurred in Q1 2018. An equal and offsetting amount was included in Operating and maintenance expense.
See Note 18 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

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ComEd

The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Baseline
 
 
 
Labor, other benefits, contracting and materials(a)
$
—

 
$
(4
)
Pension and non-pension postretirement benefits expense(b)
(8
)
 
(28
)
Storm-related costs
7

 
25

Uncollectible accounts expense — recovery, net(c)
(3
)
 
(5
)
BSC costs
12

 
6

Other(a)
(5
)
 
(1
)
Total increase (decrease)
$
3

 
$
(7
)
_________
(a)
Reflects absence of mutual assistance expenses. An equal and offsetting decrease has been recognized in Operating revenues for the period presented.
(b)
Primarily reflects an increase in discount rates and the favorable impacts of the merger of two of Exelon’s pension plans effective in January 2019, partially offset by lower than expected asset returns in 2018.
(c)
ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. During the three and nine months ended September 30, 2019, ComEd recorded a net decrease in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting increase has been recognized in Operating revenues for the period presented.
The changes in Depreciation and amortization expense consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase
 
Increase
Depreciation and amortization(a)
$
15

 
$
45

Regulatory asset amortization(b)
7

 
26

Total increase
$
22

 
$
71

_________
(a)
Reflects ongoing capital expenditures and higher depreciation rates effective January 2019.
(b)
Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Effective income tax rate was 18.4% and 21.2% for the three months ended September 30, 2019 and 2018, respectively. Effective income tax rate was 19.3% and 21.1% for the nine months ended September 30, 2019 and 2018, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PECO

Results of Operations — PECO
 
Three Months Ended
September 30,
 
Favorable
(Unfavorable)
Variance
 
Nine Months Ended
September 30,
 
Favorable
(Unfavorable)
Variance
 
2019
 
2018
 
 
2019
 
2018
 
Operating revenues
$
778

 
$
757

 
$
21

 
$
2,333

 
$
2,275

 
$
58

Purchased power and fuel expense
246

 
263

 
17

 
767

 
818

 
51

Revenues net of purchased power and fuel expense
532

 
494

 
38

 
1,566

 
1,457

 
109

Other operating expenses
 
 
 
 
 
 
 
 
 
 
 
Operating and maintenance
219

 
219

 
—

 
643

 
686

 
43

Depreciation and amortization
83

 
75

 
(8
)
 
247

 
224

 
(23
)
Taxes other than income
47

 
46

 
(1
)
 
126

 
125

 
(1
)
Total other operating expenses
349

 
340

 
(9
)
 
1,016

 
1,035

 
19

Gain on sales of assets
—

 
—

 
—

 
—

 
1

 
(1
)
Operating income
183

 
154

 
29

 
550

 
423

 
127

Other income and (deductions)
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(33
)
 
(32
)
 
(1
)
 
(100
)
 
(96
)
 
(4
)
Other, net
4

 
2

 
2

 
11

 
4

 
7

Total other income and (deductions)
(29
)
 
(30
)
 
1

 
(89
)
 
(92
)
 
3

Income before income taxes
154

 
124

 
30

 
461

 
331

 
130

Income taxes
14

 
(2
)
 
(16
)
 
51

 
(5
)
 
(56
)
Net income
$
140

 
$
126

 
$
14

 
$
410

 
$
336

 
$
74

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018. Net income increased by $14 million primarily due to higher electric distribution rates that became effective January 2019 and higher natural gas distribution rates, partially offset by unfavorable weather conditions and volume.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018. Net income increased by $74 million primarily due to higher electric distribution rates that became effective January 2019, higher natural gas distribution rates and lower storm costs, partially offset by unfavorable weather conditions and volume.
Revenues Net of Purchased Power and Fuel Expense
There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power and fuel expense such as commodity and REC procurement costs and participation in customer choice programs. PECO recovers electricity, natural gas and REC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity and natural gas.

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PECO

The changes in RNF consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
 
Electric
 
Gas
 
Total
 
Electric
 
Gas
 
Total
Weather
$
(3
)
 
$
(1
)
 
$
(4
)
 
$
(9
)
 
$
(6
)
 
$
(15
)
Volume
(7
)
 
1

 
(6
)
 
(11
)
 
6

 
(5
)
Pricing
42

 
—

 
42

 
91

 
14

 
105

Regulatory required programs
13

 
1

 
14

 
35

 
6

 
41

Transmission
(11
)
 
—

 
(11
)
 
(17
)
 
—

 
(17
)
Other
3

 
—

 
3

 
—

 
—

 
—

Total increase
$
37

 
$
1

 
$
38

 
$
89

 
$
20

 
$
109

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2019 compared to the same period in 2018, RNF related to weather decreased due to unfavorable weather conditions.
Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and nine months ended September 30, 2019 compared to the same period in 2018 and normal weather consisted of the following:
Heating and Cooling Degree-Days
 
 
Normal
 
% Change
Three Months Ended September 30,
2019
 
2018
From 2018
 
2019 vs. Normal
Heating Degree-Days
2

 
13

 
27

 
(84.6
)%
 
(92.6
)%
Cooling Degree-Days
1,143

 
1,124

 
1,001

 
1.7
 %
 
14.2
 %
 
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
 
 
 
 
 
 
 
 
 
Heating Degree-Days
2,704

 
2,892

 
2,890

 
(6.5
)%
 
(6.4
)%
Cooling Degree-Days
1,570

 
1,506

 
1,386

 
4.2
 %
 
13.3
 %
Volume. Electric volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2019 compared to the same period in 2018, decreased due to the impact of energy efficiency initiatives on customer usages for residential, commercial and industrial electric classes, partially offset by the impact of customer growth.  Natural gas volume for the three and nine months ended September 30, 2019, compared to the same period in 2018, increased due to customer and economic growth.

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PECO

Electric Retail Deliveries to Customers (in GWhs)
Three Months Ended
September 30,
 
% Change
 
Weather -
Normal
% Change(b)
 
Nine Months Ended September 30,
 
% Change
 
Weather -
Normal
% Change(b)
2019
 
2018
 
 
2019
 
2018
 
Residential
4,106

 
4,166

 
(1.4
)%
 
(0.8
)%
 
10,568

 
10,741

 
(1.6
)%
 
(0.5
)%
Small commercial & industrial
2,203

 
2,315

 
(4.8
)%
 
(2.0
)%
 
6,093

 
6,273

 
(2.9
)%
 
(1.7
)%
Large commercial & industrial
4,109

 
4,378

 
(6.1
)%
 
(6.3
)%
 
11,449

 
11,892

 
(3.7
)%
 
(3.9
)%
Public authorities & electric railroads
183

 
189

 
(3.2
)%
 
(3.3
)%
 
560

 
568

 
(1.4
)%
 
(2.0
)%
Total electric retail deliveries(a)
10,601

 
11,048

 
(4.0
)%
 
(3.3
)%
 
28,670

 
29,474

 
(2.7
)%
 
(2.1
)%
 
As of September 30,
Number of Electric Customers
2019
 
2018
Residential
1,489,046

 
1,476,914

Small commercial & industrial
153,400

 
152,253

Large commercial & industrial
3,104

 
3,124

Public authorities & electric railroads
9,775

 
9,561

Total
1,655,325

 
1,641,852

_________
(a)
Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)
Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Natural Gas Deliveries to Customers (in mmcf)
Three Months Ended
September 30,
 
% Change
 
Weather -
Normal
% Change(b)
 
Nine Months Ended
September 30,
 
% Change
 
Weather -
Normal
% Change(b)
2019
 
2018
 
 
2019
 
2018
 
Residential
2,109

 
2,099

 
0.5
 %
 
7.9
 %
 
26,678

 
28,562

 
(6.6
)%
 
1.1
%
Small commercial & industrial
1,901

 
1,776

 
7.0
 %
 
15.1
 %
 
16,585

 
15,792

 
5.0
 %
 
1.2
%
Large commercial & industrial
10

 
6

 
66.7
 %
 
12.4
 %
 
46

 
58

 
(20.7
)%
 
6.0
%
Transportation
5,395

 
5,693

 
(5.2
)%
 
(3.4
)%
 
19,087

 
19,242

 
(0.8
)%
 
1.3
%
Total natural gas retail deliveries(a)
9,415

 
9,574

 
(1.7
)%
 
2.5
 %
 
62,396

 
63,654

 
(2.0
)%
 
1.2
%
 
As of September 30,
Number of Natural Gas Customers
2019
 
2018
Residential
484,676

 
479,732

Small commercial & industrial
43,869

 
43,638

Large commercial & industrial
2

 
1

Transportation
735

 
761

Total
529,282

 
524,132

_________
(a)
Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)
Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three and nine months ended September 30, 2019 compared to the same period in 2018 increased primarily due to an increase in electric distribution rates charged to customers.  The increase in electric distribution rates was effective January 1, 2019 in accordance with the 2018 PAPUC approved electric distribution rate case settlement. Additionally, the increase represents revenue from higher natural gas distribution rates. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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PECO

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Income taxes.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the three and nine months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to lower income taxes and operating and maintenance expenses. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes rental revenue, revenue related to late payment charges and mutual assistance revenues.
See Note 18— Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Baseline
 
 
 
Labor, other benefits, contracting and materials
$
(5
)
 
$
4

Storm-related costs(a)
8

 
(42
)
Pension and non-pension postretirement benefits expense
(1
)
 
(4
)
BSC costs
2

 
4

Other
(5
)
 
(6
)
 
(1
)
 
(44
)
Regulatory Required Programs
 
 
 
Energy efficiency
1

 
1

Total decrease
$
—

 
$
(43
)
__________
(a)
Reflects decreased storm costs due to the March 2018 winter storms.
The changes in Depreciation and amortization expense consisted of the following:
 
Three Months Ended September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase
 
Increase
Depreciation and amortization(a)
$
7

 
$
21

Regulatory asset amortization
1

 
2

Total increase
$
8

 
$
23

__________
(a)
Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective Income Tax Rates were 9.1% and (1.6)% for the three months ended September 30, 2019 and 2018, respectively, and 11.1% and (1.5)% for the nine months ended September 30, 2019 and 2018, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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BGE


Results of Operations — BGE
 
Three Months Ended
September 30,
 
Favorable
(Unfavorable)
Variance
 
Nine Months Ended
September 30,
 
Favorable
(Unfavorable)
Variance
 
2019
 
2018
 
 
2019
 
2018
 
Operating revenues
$
703

 
$
731

 
$
(28
)
 
$
2,327

 
$
2,369

 
$
(42
)
Purchased power and fuel expense
235

 
272

 
37

 
804

 
881

 
77

Revenues net of purchased power and fuel expense
468

 
459

 
9

 
1,523

 
1,488

 
35

Other operating expenses
 
 
 
 
 
 
 
 
 
 
 
Operating and maintenance
196

 
182

 
(14
)
 
569

 
578

 
9

Depreciation and amortization
116

 
110

 
(6
)
 
368

 
358

 
(10
)
Taxes other than income
65

 
64

 
(1
)
 
195

 
188

 
(7
)
Total other operating expenses
377

 
356

 
(21
)
 
1,132

 
1,124

 
(8
)
Gain on sales of assets
—

 
—

 
—

 
—

 
1

 
(1
)
Operating income
91

 
103

 
(12
)
 
391

 
365

 
26

Other income and (deductions)
 
 
 
 
 
 
 
 
 
 
 
Interest expense, net
(31
)
 
(27
)
 
(4
)
 
(89
)
 
(78
)
 
(11
)
Other, net
7

 
5

 
2

 
18

 
14

 
4

Total other income and (deductions)
(24
)
 
(22
)
 
(2
)
 
(71
)
 
(64
)
 
(7
)
Income before income taxes
67

 
81

 
(14
)
 
320

 
301

 
19

Income taxes
12

 
18

 
6

 
59

 
59

 
—

Net income
$
55

 
$
63

 
$
(8
)
 
$
261

 
$
242

 
$
19

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018. Net income decreased by $8 million primarily due to an increase in various expenses, partially offset by higher natural gas distribution rates that became effective January 2019.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018. Net income increased by $19 million primarily due to higher natural gas distribution rates that became effective January 2019 and lower storm costs, partially offset by an increase in various expenses, including interest.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and participation in customer choice programs. BGE recovers electricity, natural gas and procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity and natural gas from electric generation and natural gas competitive suppliers. Customer choice programs do not impact the volume of deliveries or RNF but impact Operating revenues related to supplied electricity and natural gas.

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Table of Contents
BGE


The changes in RNF consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
 
Electric
 
Gas
 
Total
 
Electric
 
Gas
 
Total
Distribution
$
2

 
$
7

 
$
9

 
$
7

 
$
48

 
$
55

Regulatory required programs
(1
)
 
1

 
—

 
(6
)
 
(3
)
 
(9
)
Transmission
2

 
—

 
2

 
(3
)
 
—

 
(3
)
Other, net
—

 
(2
)
 
(2
)
 
(4
)
 
(4
)
 
(8
)
Total increase (decrease)
$
3

 
$
6

 
$
9

 
$
(6
)
 
$
41

 
$
35

Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
 
As of September 30,
Number of Electric Customers
2019
 
2018
Residential
1,174,188

 
1,165,012

Small commercial & industrial
114,301

 
114,082

Large commercial & industrial
12,296

 
12,218

Public authorities & electric railroads
264

 
263

Total
1,301,049

 
1,291,575

 
As of September 30,
Number of Natural Gas Customers
2019
 
2018
Residential
636,030

 
631,589

Small commercial & industrial
38,129

 
38,175

Large commercial & industrial
6,005

 
5,920

Total
680,164

 
675,684

Distribution Revenue increased for the three and nine months ended September 30, 2019, compared to the same period in 2018, primarily due to the impact of higher natural gas distribution rates that became effective in January 2019. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue remained relatively consistent for the three and nine months ended September 30, 2019, compared to the same period in 2018. See Operating and maintenance expense below and Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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BGE


Other revenue includes revenue related to mutual assistance, administrative charges, off-system sales, and late payment charges.
See Note 18 — Segment Information of the Combined Notes to the Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Baseline
 
 
 
Storm-related costs(a)
$
(3
)
 
$
(26
)
Labor, other benefits, contracting and materials
12

 
16

Pension and non-pension postretirement benefits expense
—

 
1

Uncollectible accounts expense
(1
)
 
(1
)
BSC costs
1

 
2

Other
5

 
—

 
14

 
(8
)
Regulatory Required Programs
 
 
 
Other
—

 
(1
)
Total increase (decrease)
$
14

 
$
(9
)
__________
(a)
For the nine months ended September 30, 2019, reflects decreased storm costs due to the March 2018 winter storms.
The changes in Depreciation and amortization expense consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Depreciation and amortization(a)
$
4

 
$
15

Regulatory asset amortization
2

 
3

Regulatory required programs
—

 
(8
)
Total increase
$
6

 
$
10

_________
(a)
Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net for the three and nine months ended September 30, 2019 compared to the same period in 2018, increased due to the issuance of debt in September 2018.
Effective income tax rates were 17.9% and 22.2% for the three months ended September 30, 2019 and 2018, respectively, and 18.4% and 19.6% for the nine months ended September 30, 2019 and 2018, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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Table of Contents
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
September 30,
 
Favorable (Unfavorable) Variance
 
Nine Months Ended
September 30,
 
Favorable
(Unfavorable)
Variance
 
2019
 
2018
 
 
2019
 
2018
 
PHI
$
189

 
$
187

 
$
2

 
$
412

 
$
336

 
$
76

Pepco
98

 
89

 
9

 
217

 
174

 
43

DPL
33

 
33

 
—

 
116

 
90

 
26

ACE
63

 
61

 
2

 
87

 
76

 
11

Other(a)
(5
)
 
4

 
(9
)
 
(8
)
 
(4
)
 
(4
)
_________
(a)
Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities and other financing and investing activities.
Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018. Net Income remained relatively consistent with the same period in 2018 primarily due to higher electric and natural gas distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, partially offset by an increase in environmental liabilities and various expenses.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018. Net Income increased by $76 million primarily due to higher electric and natural gas distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, lower contracting costs, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, lower uncollectible accounts expense, and lower write-offs of construction work in progress, partially offset by an increase in environmental liabilities and various expenses.

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Pepco


Results of Operations — Pepco
 
Three Months Ended September 30,
 
Favorable (Unfavorable) Variance
 
Nine Months Ended September 30,
 
Favorable (Unfavorable) Variance
2019
 
2018
 
 
2019
 
2018
 
Operating revenues
$
642

 
$
628

 
$
14

 
$
1,748

 
$
1,708

 
$
40

Purchased power expense
181

 
177

 
(4
)
 
513

 
497

 
(16
)
Revenues net of purchased power expense
461

 
451

 
10

 
1,235

 
1,211

 
24

Other operating expenses
 
 
 
 
 
 
 
 
 
 
 
Operating and maintenance
135

 
136

 
1

 
364

 
383

 
19

Depreciation and amortization
95

 
99

 
4

 
281

 
286

 
5

Taxes other than income
104

 
104

 
—

 
286

 
288

 
2

Total other operating expenses
334

 
339

 
5

 
931

 
957

 
26

Operating income
127

 
112

 
15

 
304

 
254

 
50

Other income and (deductions)
 
 
 
 

 
 
 
 
 

Interest expense, net
(33
)
 
(32
)
 
(1
)
 
(100
)
 
(96
)
 
(4
)
Other, net
9

 
7

 
2

 
22

 
23

 
(1
)
Total other income and (deductions)
(24
)
 
(25
)
 
1

 
(78
)
 
(73
)
 
(5
)
Income before income taxes
103

 
87

 
16

 
226

 
181

 
45

Income taxes
5

 
(2
)
 
(7
)
 
9

 
7

 
(2
)
Net income
$
98

 
$
89

 
$
9

 
$
217

 
$
174

 
$
43

Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2018. Net income increased by $9 million primarily due to higher electric distribution rates in Maryland that became effective August 2019, higher electric distribution rates in the District of Columbia that became effective August 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, partially offset by an increase in environmental liabilities.
Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018. Net income increased by $43 million primarily due to higher electric distribution rates in Maryland that became effective August 2019 and June 2018 (not reflecting the impact of TCJA), higher electric distribution rates in the District of Columbia that became effective August 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, lower contracting costs, and lower uncollectible accounts expense, partially offset by an increase in environmental liabilities.
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity and REC procurement costs and participation in customer choice programs. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity.

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Table of Contents
Pepco


The changes in RNF consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Volume
$
4

 
$
11

Distribution
9

 
19

Regulatory required programs
(8
)
 
(26
)
Transmission
2

 
22

Other
3

 
(2
)
Total increase
$
10

 
$
24

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
Volume, exclusive of the effects of weather, increased for the three and nine months ended September 30, 2019 compared to the same period in 2018, primarily due to the impact of residential customer growth.
 
As of September 30,
Number of Electric Customers
2019
 
2018
Residential
814,412

 
802,607

Small commercial & industrial
54,130

 
53,700

Large commercial & industrial
22,240

 
21,927

Public authorities & electric railroads
158

 
147

Total
890,940

 
878,381

Distribution Revenues increased for the three and nine months ended September 30, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates in Maryland that became effective in August 2019 and June 2018 (not reflecting the impact of TCJA), higher electric distribution rates (not reflecting the impact of TCJA) in the District of Columbia that became effective in August 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 6 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG and SOS administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.
Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenues increased for the three and nine months ended September 30, 2019 compared to the same period in 2018 primarily due to rate increases and an increase in the highest daily peak load.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of other taxes.

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Pepco


See Note 18 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Baseline
 
 
 
Labor, other benefits, contracting and materials
$
(2
)
 
$
(14
)
Pension and non-pension postretirement benefits expense
2

 
5

Uncollectible accounts expense
1

 
(4
)
Storm-related costs
2

 
(1
)
BSC and PHISCO costs
(2
)
 
(9
)
Other
(2
)
 
7

 
(1
)
 
(16
)
 
 
 
 
Regulatory required programs
—

 
(3
)
Total decrease
$
(1
)
 
$
(19
)
The changes in Depreciation and amortization expense consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Depreciation and amortization(a)
$
6

 
$
17

Regulatory required programs
(10
)
 
(22
)
Total decrease
$
(4
)
 
$
(5
)
_________
(a)
Depreciation and amortization increased primarily due to ongoing capital expenditures.

Interest expense, net for the nine months ended September 30, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.
Effective income tax rates were 4.9% and (2.3)% for the three months ended September 30, 2019 and 2018, respectively, and 4.0% and 3.9% for the nine months ended September 30, 2019 and 2018, respectively. The increase is primarily due to the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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Table of Contents
DPL


Results of Operations — DPL
 
Three Months Ended September 30,
 
Favorable (Unfavorable) Variance
 
Nine Months Ended September 30,
 
Favorable (Unfavorable) Variance
2019
 
2018
 
 
2019
 
2018
 
Operating revenues
$
319

 
$
328

 
$
(9
)
 
$
987

 
$
1,001

 
$
(14
)
Purchased power and fuel expense
127

 
133

 
6

 
399

 
425

 
26

Revenues net of purchased power and fuel expense
192

 
195

 
(3
)
 
588

 
576

 
12

Other operating expenses


 


 
 
 


 


 
 
Operating and maintenance
80

 
82

 
2

 
240

 
256

 
16

Depreciation and amortization
46

 
47

 
1

 
138

 
135

 
(3
)
Taxes other than income
15

 
15

 
—

 
43

 
43

 
—

Total other operating expenses
141

 
144

 
3

 
421

 
434

 
13

Operating income
51

 
51

 
—

 
167

 
142

 
25

Other income and (deductions)


 


 


 


 


 


Interest expense, net
(15
)
 
(15
)
 
—

 
(45
)
 
(42
)
 
(3
)
Other, net
2

 
2

 
—

 
10

 
7

 
3

Total other income and (deductions)
(13
)
 
(13
)
 
—

 
(35
)
 
(35
)
 
—

Income before income taxes
38


38

 
—

 
132


107

 
25

Income taxes
5

 
5

 
—

 
16

 
17

 
1

Net income
$
33

 
$
33

 
$
—

 
$
116

 
$
90

 
$
26

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

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Table of Contents
DPL


The changes in RNF consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
 
Electric
 
Gas
 
Total
 
Electric
 
Gas
 
Total
Weather
$
—

 
$
—

 
$
—

 
$
—

 
$
(2
)
 
$
(2
)
Volume
—

 
(1
)
 
(1
)
 
—

 
1

 
1

Distribution
1

 
—

 
1

 
3

 
—

 
3

Regulatory required programs
(2
)
 
1

 
(1
)
 
(6
)
 
1

 
(5
)
Transmission
1

 
—

 
1

 
18

 
—

 
18

Other
(3
)
 
—

 
(3
)
 
(3
)
 
—

 
(3
)
Total increase (decrease)
$
(3
)
 
$
—

 
$
(3
)
 
$
12

 
$
—

 
$
12

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2019 compared to the same period in 2018, RNF related to weather remained relatively consistent.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the three and nine months ended September 30, 2019 compared to same period in 2018 and normal weather consisted of the following:
Delaware Electric Service Territory
 
 
 
 
% Change
Three Months Ended September 30,
2019
 
2018
 
Normal
 
2019 vs. 2018
 
2019 vs. Normal
Heating Degree-Days
6

 
11

 
33

 
(45.5
)%
 
(81.8
)%
Cooling Degree-Days
1,043

 
1,027

 
871

 
1.6
 %
 
19.7
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
% Change
Nine Months Ended September 30,
2019
 
2018
 
Normal
 
2019 vs. 2018
 
2019 vs. Normal
Heating Degree-Days
2,828

 
2,995

 
3,017

 
(5.6
)%
 
(6.3
)%
Cooling Degree-Days
1,429

 
1,376

 
1,198

 
3.9
 %
 
19.3
 %
Delaware Natural Gas Service Territory
 
 
 
 
% Change
Three Months Ended September 30,
2019
 
2018
 
Normal
 
2019 vs. 2018
 
2019 vs. Normal
Heating Degree-Days
6

 
11

 
41

 
(45.5
)%
 
(85.4
)%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
% Change
Nine Months Ended September 30,
2019
 
2018
 
Normal
 
2019 vs. 2018
 
2019 vs. Normal
Heating Degree-Days
2,828

 
2,995

 
3,031

 
(5.6
)%
 
(6.7
)%

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Table of Contents
DPL


Volume, exclusive of the effects of weather, remained relatively consistent for the three and nine months ended September 30, 2019 compared to the same period in 2018.
Electric Retail Deliveries to Delaware Customers (in GWhs)
Three Months Ended
September 30,
 
% Change
 
Weather - Normal
% Change(b)
 
Nine Months Ended
September 30,
 
% Change
 
Weather - Normal
% Change(b)
2019
 
2018
 
 
 
2019
 
2018
 
 
Residential
947

 
945

 
0.2
 %
 
0.3
 %
 
2,450

 
2,485

 
(1.4
)%
 
(0.6
)%
Small commercial & industrial
387

 
376

 
2.9
 %
 
2.5
 %
 
1,013

 
1,027

 
(1.4
)%
 
(1.3
)%
Large commercial & industrial
924

 
973

 
(5.0
)%
 
(5.2
)%
 
2,600

 
2,730

 
(4.8
)%
 
(4.8
)%
Public authorities & electric railroads
8

 
8

 
—
 %
 
(1.1
)%
 
25

 
25

 
—
 %
 
1.1
 %
Total electric retail deliveries(a)
2,266

 
2,302

 
(1.6
)%
 
(1.7
)%
 
6,088

 
6,267

 
(2.9
)%
 
(2.6
)%
 
As of September 30,
Number of Total Electric Customers (Maryland and Delaware)
2019
 
2018
Residential
466,972

 
463,017

Small commercial & industrial
61,657

 
61,277

Large commercial & industrial
1,418

 
1,400

Public authorities & electric railroads
616

 
622

Total
530,663

 
526,316

_________
(a)
Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)
Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Natural Gas Retail Deliveries to Delaware Customers (in mmcf)
Three Months Ended
September 30,
 
% Change
 
Weather - Normal
% Change(b)
 
Nine Months Ended
September 30,
 
% Change
 
Weather - Normal
% Change(b)
2019
 
2018
 
 
 
2019
 
2018
 
 
Residential
403

 
360

 
11.9
 %
 
11.8
 %
 
5,751

 
5,801

 
(0.9
)%
 
3.8
 %
Small commercial & industrial
386

 
309

 
24.9
 %
 
22.9
 %
 
2,972

 
2,831

 
5.0
 %
 
8.9
 %
Large commercial & industrial
407

 
454

 
(10.4
)%
 
(10.4
)%
 
1,372

 
1,438

 
(4.6
)%
 
(4.5
)%
Transportation
1,212

 
1,260

 
(3.8
)%
 
(3.5
)%
 
4,905

 
4,893

 
0.2
 %
 
1.6
 %
Total natural gas deliveries(a)
2,408

 
2,383

 
1.0
 %
 
1.4
 %
 
15,000

 
14,963

 
0.2
 %
 
3.3
 %
 
As of September 30,
Number of Delaware Natural Gas Customers
2019
 
2018
Residential
124,944

 
123,145

Small commercial & industrial
9,885

 
9,798

Large commercial & industrial
18

 
19

Transportation
158

 
154

Total
135,005

 
133,116

__________
(a)
Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)
Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

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DPL


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

Pension and non-pension postretirement benefits expense
1

 
3

Uncollectible accounts expense
(3
)
 
(4
)
Storm-related costs
2

 
(1
)
BSC and PHISCO costs
(1
)
 
(6
)
Write-offs of construction work in progress
—

 
(7
)
Other
1

 
(1
)
 
(2
)
 
(15
)
 
 
 
 
Regulatory required programs
—

 
(1
)
Total decrease
$
(2
)
 
$
(16
)
The changes in Depreciation and amortization expense consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Depreciation and amortization(a)
$
4

 
$
11

Regulatory asset amortization
(1
)
 
(1
)
Regulatory required programs
(4
)
 
(7
)
Total increase (decrease)
$
(1
)
 
$
3

_________
(a)
Depreciation and amortization increased primarily due to ongoing capital expenditures.

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DPL


Interest expense, net for the nine months ended September 30, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.
Effective income tax rates were 13.2% and 13.2% for the three months ended September 30, 2019 and 2018, respectively, and 12.1% and 15.9% for the nine months ended September 30, 2019 and 2018, respectively. The decrease for the nine months ended September 30, 2019 is primarily due to the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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ACE


Results of Operations — ACE
 
Three Months Ended September 30,
 
Favorable (Unfavorable) Variance
 
Nine Months Ended September 30,
 
Favorable (Unfavorable) Variance
 
2019
 
2018
 
 
2019
 
2018
 
Operating revenues
$
419

 
$
406

 
$
13

 
$
966

 
$
981

 
$
(15
)
Purchased power expense
210

 
198

 
(12
)
 
479

 
486

 
7

Revenues net of purchased power expense
209

 
208

 
1

 
487

 
495

 
(8
)
Other operating expenses
 
 
 
 

 
 
 
 
 

Operating and maintenance
86

 
85

 
(1
)
 
241

 
250

 
9

Depreciation and amortization
43

 
38

 
(5
)
 
114

 
107

 
(7
)
Taxes other than income
1

 
1

 
—

 
4

 
4

 
—

Total other operating expenses
130

 
124

 
(6
)
 
359

 
361

 
2

Operating income
79

 
84

 
(5
)
 
128

 
134

 
(6
)
Other income and (deductions)
 
 
 
 

 
 
 
 
 

Interest expense, net
(15
)
 
(16
)
 
1

 
(44
)
 
(48
)
 
4

Other, net
1

 
1

 
—

 
5

 
2

 
3

Total other income and (deductions)
(14
)

(15
)
 
1

 
(39
)

(46
)
 
7

Income before income taxes
65


69

 
(4
)
 
89


88

 
1

Income taxes
2

 
8

 
6

 
2

 
12

 
10

Net income
$
63

 
$
61

 
$
2

 
$
87

 
$
76

 
$
11

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

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ACE


The changes in RNF consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Weather
$
(4
)
 
$
(4
)
Volume
(4
)
 
(10
)
Distribution
16

 
21

Regulatory required programs
(12
)
 
(28
)
Transmission
7

 
15

Other
(2
)
 
(2
)
Total increase (decrease)
$
1

 
$
(8
)
Weather. The demand for electricity is affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. There was a decrease related to weather for the three and nine months ended September 30, 2019 compared to same period in 2018 due to the impact of unfavorable weather conditions in ACE's service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating degree days in ACE’s service territory for the three and nine months ended September 30, 2019 compared to same period in 2018 consisted of the following:
Heating and Cooling Degree-Days
 
 
Normal
 
% Change
Three Months Ended September 30,
2019
 
2018
 
 
2019 vs. 2018
 
2019 vs. Normal
Heating Degree-Days
13

 
1

 
38

 
1,200.0
 %
 
(65.8
)%
Cooling Degree-Days
980

 
1,093

 
831

 
(10.3
)%
 
17.9
 %
 
 
 
 
 
 
 
 
 
 
 
 
 
Normal
 
% Change
Nine Months Ended September 30,
2019
 
2018
 
 
2019 vs. 2018
 
2019 vs. Normal
Heating Degree-Days
2,899

 
2,928

 
3,080

 
(1.0
)%
 
(5.9
)%
Cooling Degree-Days
1,330

 
1,447

 
1,129

 
(8.1
)%
 
17.8
 %
Volume, exclusive of the effects of weather, decreased for the three and nine months ended September 30, 2019 compared to the same period in 2018, primarily due to lower average residential usage.
Electric Retail Deliveries to Customers (in GWhs)
Three Months Ended
September 30,
 
% Change
 
Weather - Normal % Change(b)
 
Nine Months Ended
September 30,
 
% Change
 
Weather - Normal
% Change(b)
2019
 
2018
 
 
 
2019
 
2018
 
 
Residential
1,470

 
1,548

 
(5.0
)%
 
(1.6
)%
 
3,182

 
3,363

 
(5.4
)%
 
(3.9
)%
Small commercial & industrial
431

 
442

 
(2.5
)%
 
(0.5
)%
 
1,055

 
1,066

 
(1.0
)%
 
0.1
 %
Large commercial & industrial
938

 
1,030

 
(8.9
)%
 
(7.9
)%
 
2,600

 
2,725

 
(4.6
)%
 
(4.2
)%
Public authorities & electric railroads
10

 
10

 
—
 %
 
(3.9
)%
 
34

 
36

 
(5.6
)%
 
(5.9
)%
Total electric retail deliveries(a)
2,849

 
3,030

 
(6.0
)%
 
(3.7
)%
 
6,871

 
7,190

 
(4.4
)%
 
(3.4
)%

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ACE


 
As of September 30,
Number of Electric Customers
2019
 
2018
Residential
493,720

 
489,961

Small commercial & industrial
61,376

 
61,141

Large commercial & industrial
3,418

 
3,569

Public authorities & electric railroads
676

 
656

Total
559,190

 
555,327

_________
(a)
Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
(b)
Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Distribution Revenue increased for the three and nine months ended September 30, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates charged to customers that became effective in April 2019, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds and BGS administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.
Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the three and nine months ended September 30, 2019 compared to the same period in 2018 primarily due to rate increases and an increase in the highest daily peak load.
See Note 18 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Baseline
 
 
 
Labor, other benefits, contracting and materials
$
2

 
$
(4
)
Uncollectible accounts expense(a)
(3
)
 
(9
)
Storm-related costs
1

 
1

BSC and PHISCO costs
(1
)
 
(4
)
Other
3

 
(4
)
 
2

 
(20
)
 
 
 
 
Regulatory required programs
(1
)
 
11

Total Increase (Decrease)
$
1

 
$
(9
)
_________
(a)
ACE is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues.

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ACE


The changes in Depreciation and amortization expense consisted of the following:
 
Three Months Ended
September 30, 2019
 
Nine Months Ended
September 30, 2019
 
Increase (Decrease)
 
Increase (Decrease)
Depreciation and amortization(a)
$
8

 
$
19

Regulatory asset amortization(b)
3

 
5

Regulatory required programs
(6
)
 
(17
)
Total increase
$
5

 
$
7

_________
(a)
Depreciation and amortization increased primarily due to ongoing capital expenditures.
(b)
Regulatory asset amortization increased primarily due to additional regulatory assets related to rate case activity.
Interest expense, net for the nine months ended September 30, 2019 compared to the same period in 2018 decreased primarily due to lower outstanding debt.
Other, net for the nine months ended September 30, 2019 compared to the same period in 2018 increased primarily due to higher income from AFUDC equity.
Effective income tax rates were 3.1% and 11.6% for the three months ended September 30, 2019 and 2018, respectively and 2.2% and 13.6% for the nine months ended September 30, 2019 and 2018, respectively. The decrease is primarily due to the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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Table of Contents

Liquidity and Capital Resources
All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to unsecured revolving credit facilities with aggregate bank commitments of $9 billion. In addition, Generation has $645 million in bilateral facilities with banks which have various expirations between October 2019 and April 2021 and $159 million in credit facilities for project finance. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
NRC Minimum Funding Requirements (Exelon and Generation)
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.
If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value. A shortfall could require that Generation address the shortfall by, among other things, obtaining a parental guarantee for Generation’s share of the funding assurance. However, the amount of any guarantees or other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. 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.


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As of September 30, 2019, 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 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. Refer to Note 13 — Debt and Credit Agreements of the Exelon 2018 Form 10-K for additional information on credit facilities.
Pension Funding Strategy (All Registrants)
Management considers various factors when making qualified pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). Beginning in 2020, Exelon will implement a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $500 million beginning in 2020. This funding strategy does not change Exelon’s expected 2019 qualified pension contributions of approximately $300 million.
Cash Flows from Operating Activities (All Registrants)
General
Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers.
The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions.
See Notes 4 — Regulatory Matters and 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2018 Form 10-K for additional information of regulatory and legal proceedings and proposed legislation.
The following table provides a summary of the change in cash flows from operating activities for the nine months ended September 30, 2019 and 2018 by Registrant:

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Table of Contents

Increase (Decrease) in cash flows from operating activities
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Net income
$
241

 
$
117

 
$
21

 
$
74

 
$
19

 
$
76

 
$
43

 
$
26

 
$
11

Adjustments to reconcile net income to cash:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Non-cash operating activities
(399
)
 
(293
)
 
(35
)
 
12

 
15

 
(22
)
 
13

 
(18
)
 
(18
)
Pension and non-pension postretirement benefit contributions
(15
)
 
(31
)
 
(30
)
 
(1
)
 
5

 
51

 
1

 
(1
)
 
6

Income taxes
(23
)
 
107

 
90

 
1

 
5

 
20

 
(5
)
 
11

 
8

Changes in working capital and other noncurrent assets and liabilities
(653
)
 
(367
)
 
(72
)
 
(40
)
 
(50
)
 
(93
)
 
(63
)
 
(31
)
 
19

Option premiums received, net
49

 
49

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Collateral posted, net
(476
)
 
(520
)
 
53

 
—

 
(6
)
 
—

 
—

 
—

 
—

(Decrease) Increase in cash flows from operating activities
$
(1,276
)
 
$
(938
)
 
$
27

 
$
46

 
$
(12
)
 
$
32

 
$
(11
)
 
$
(13
)
 
$
26

Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for the Registrants for the nine months ended September 30, 2019 and 2018 were as follows:
•
See Note 17 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statement of Cash Flows for additional information on non-cash operating activity.
•
Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the OTC markets.
Cash Flows from Investing Activities (All Registrants)
The following table provides a summary of the change in cash flows from investing activities for the nine months ended September 30, 2019 and 2018 by Registrant:
Increase (Decrease) in cash flows from investing activities
Exelon
 
Generation
 
ComEd
 
PECO
 
BGE
 
PHI
 
Pepco
 
DPL
 
ACE
Capital expenditures
$
238

 
$
378

 
$
127

 
$
(60
)
 
$
(175
)
 
$
(18
)
 
$
20

 
$
9

 
$
(53
)
Proceeds from NDT fund sales, net
180

 
180

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Acquisitions of assets and businesses, net
57

 
57

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Proceeds from sales of assets and businesses
(73
)
 
(73
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Other investing activities
(8
)
 
(1
)
 
3

 
1

 
(4
)
 
1

 
(1
)
 
—

 
1

Increase (Decrease) in cash flows from investing activities
$
394

 
$
541

 
$
130

 
$
(59
)
 
$
(179
)
 
$
(17
)
 
$
19

 
$
9

 
$
(52
)
Significant investing cash flow impacts for the Registrants for nine months ended September 30, 2019 and 2018 were as follows:
•
Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer to Liquidity and Capital Resources of the Exelon 2018 Form 10-K for additional information on projected capital expenditure spending.
•
During the nine months ended September 30, 2018, Exelon and Generation had proceeds of $79 million relating to the sale of its interest in an electrical contracting business.

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Capital Expenditure Spending
As of September 30, 2019, there have been no material changes to the Registrants’ projected capital expenditures as disclosed in Liquidity and Capital Resources of the Exelon 2018 Form 10-K.
Cash Flows from Financing Activities (All Registrants)
The following table provides a summary of the change in cash flows from financing activities for the nine months ended September 30, 2019 and 2018 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
$
398

 
$
—

 
$
387

 
$
—

 
$
42

 
$
(31
)
 
$
(66
)
 
$
273

 
$
37

Long-term debt, net
(252
)
 
(69
)
 
(410
)
 
125

 
100

 
13

 
50

 
(196
)
 
(116
)
Changes in intercompany money pool
—

 
(46
)
 
—

 
—

 
—

 
—

 
—

 
—

 
—

Dividends paid on common stock
(56
)
 
—

 
(35
)
 
32

 
(12
)
 
—

 
(45
)
 
(47
)
 
(54
)
Distributions to member
—

 
14

 
—

 
—

 
—

 
(197
)
 
—

 
—

 
—

Contributions from parent/member
—

 
(54
)
 
(200
)
 
103

 
86

 
46

 
44

 
(150
)
 
155

Other financing activities
58

 
9

 
6

 
16

 
(5
)
 
1

 
1

 
3

 
(1
)
Increase (Decrease) in cash flows from financing activities
$
148

 
$
(146
)
 
$
(252
)
 
$
276

 
$
211

 
$
(168
)
 
$
(16
)
 
$
(117
)
 
$
21

Significant financing cash flow impacts for the Registrants for the nine months ended September 30, 2019 and 2018 were as follows:
•
Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 90 days. Refer to 11 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on short-term borrowings.
•
Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to 11 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on debt issuances. Refer to debt redemptions tables below for more information.
•
Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
•
Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2018 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
Debt
See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

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During the nine months ended September 30, 2019, the following long-term debt was retired and/or redeemed:
Company (a)
 
Type
 
Interest Rate
 
Maturity
 
Amount
Exelon
 
Oracle Annual Lease Payment
 
3.95
%
 
May 1, 2024
 
$
18

Generation
 
Antelope Valley DOE Nonrecourse Debt
 
2.33% - 3.56%

 
January 5, 2037
 
12

Generation
 
Kennett Square Capital Lease
 
7.83
%
 
September 20, 2020
 
3

Generation
 
Continental Wind Nonrecourse Debt
 
6.00
%
 
February 28, 2033
 
32

Generation
 
Pollution control notes
 
2.50
%
 
March 1, 2019
 
23

Generation
 
Renewable Power Generation Nonrecourse Debt
 
4.11
%
 
March 31, 2035
 
10

Generation
 
Energy Efficiency Project Financing
 
3.46
%
 
April 30, 2019
 
39

Generation
 
ExGen Renewables IV Nonrecourse debt
 
3mL +3%

 
November 30, 2024
 
38

Generation
 
Hannie Mae, LLC Defense Financing
 
4.12
%
 
November 30, 2019
 
1

Generation
 
Energy Efficiency Project Financing
 
3.72
%
 
July 31, 2019
 
25

Generation
 
Nuclear fuel procurement contracts
 
3.15
%
 
September 30, 2020
 
36

Generation
 
SolGen Nonrecourse Debt
 
3.93
%
 
September 30, 2036
 
2

Generation
 
Energy Efficiency Project Financing
 
4.17
%
 
August 31, 2019
 
1

Generation
 
Energy Efficiency Project Financing
 
3.53
%
 
March 31, 2020
 
1

Generation
 
Energy Efficiency Project Financing
 
4.26
%
 
September 30, 2019
 
1

ComEd
 
First Mortgage Bonds
 
2.15
%
 
January 15, 2019
 
300

Pepco
 
Unsecured Tax-Exempt Bonds
 
6.20
%
 
September 1, 2022
 
110

ACE
 
Transition Bonds
 
5.55
%
 
October 20, 2023
 
13

                    
(a)
On October 1, 2019, Generation redeemed $600 million of 5.20% 2009 Senior Notes due to maturity.
Antelope Valley’s nonrecourse debt of approximately $495 million was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of September 30, 2019 as a result of the PG&E bankruptcy filing on January 29, 2019. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 2019 and for the third quarter of 2019 were as follows:
Period
 
Declaration Date
 
Shareholder of Record Date
 
Dividend Payable Date
 
Cash per Share(a)
First Quarter 2019
 
February 5, 2019
 
February 20, 2019
 
March 8, 2019
 
$
0.3625

Second Quarter 2019
 
April 30, 2019
 
May 15, 2019
 
June 10, 2019
 
$
0.3625

Third Quarter 2019
 
July 30, 2019
 
August 15, 2019
 
September 10, 2019
 
$
0.3625

_________
(a)
Exelon's Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020.
Other
For the nine months ended September 30, 2019, other financing activities primarily consist of debt issuance costs. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.

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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 $9.8 billion in aggregate total commitments of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper market during the third quarter of 2019 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PART I. ITEM 1A. RISK FACTORS of the Exelon 2018 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flow from operating activities, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of September 30, 2019, it would have been required to provide incremental collateral of $1.5 billion to meet collateral obligations for derivatives, non-derivatives, normal purchases and normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within the $4.2 billion of available credit capacity of its revolver.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at September 30, 2019 and available credit facility capacity prior to any incremental collateral at September 30, 2019:
 
PJM Credit Policy Collateral
 
Other Incremental Collateral Required(a)
 
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd
$
10

 
$
—

 
$
995

PECO
—

 
28

 
600

BGE
12

 
26

 
594

Pepco
10

 
—

 
290

DPL
6

 
11

 
300

ACE
—

 
—

 
300

_________
(a)
Represents incremental collateral related to natural gas procurement contracts.
Exelon Credit Facilities
Exelon Corporate, ComEd, BGE, Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See 11 — Debt and Credit Agreements and Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ short-term borrowing activity.
See Note 13 — Debt and Credit Agreements and Note 22 — Commitments and Contingencies of the Exelon 2018 Form 10-K for additional information on the Registrants’ credit facilities.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.

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The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of September 30, 2019, are presented in the following table:
Exelon Intercompany Money Pool
 
During the Three Months Ended September 30, 2019
 
As of September 30, 2019
Contributed (Borrowed)
 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
Exelon Corporate
 
$
260

 
$
—

 
$
206

Generation
 
212

 
—

 
—

PECO
 
7

 
(85
)
 
—

BSC
 
—

 
(338
)
 
(251
)
PHI Corporate
 
—

 
(10
)
 
(10
)
PCI
 
55

 
—

 
55

PHI Intercompany Money Pool
 
During the Three Months Ended September 30, 2019
 
As of September 30, 2019
Contributed (Borrowed)
 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
Pepco
 
63

 
—

 
—

DPL
 
—

 
(46
)
 
—

ACE
 
—

 
(29
)
 
—

PHISCO
 
2

 
—

 
2

Shelf Registration Statements
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 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 September 30, 2019
 
 
Short-term Financing Authority(a)(b)
 
Remaining Long-term Financing Authority(a)
Commission
 
Expiration Date
 
Amount
Commission
 
Expiration Date
 
Amount
ComEd(c)
 
FERC
 
December 31, 2019
 
$
2,500

 
ICC
 
August 1, 2021
 
$
693

PECO
 
FERC
 
December 31, 2019
 
1,500

 
PAPUC
 
December 31, 2021
 
1,575

BGE
 
FERC
 
December 31, 2019
 
700

 
MDPSC
 
N/A
 
—

Pepco
 
FERC
 
December 31, 2019
 
500

 
MDPSC / DCPSC
 
December 31, 2020
 
141

DPL
 
FERC
 
December 31, 2019
 
500

 
MDPSC / DPSC
 
December 31, 2020
 
150

ACE
 
NJBPU
 
December 31, 2019
 
350

 
NJBPU
 
December 31, 2020
 
200

_________
(a)
Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.
(b)
On October 15, 2019, ComEd, PECO, BGE, Pepco and DPL filed applications with FERC and on September 12, 2019, ACE filed an application with NJBPU for renewal of their short-term financing authority through December 31, 2021. ComEd, PECO, BGE, Pepco, DPL and ACE expect approval of the applications before the end of the year.
(c)
ComEd had $693 million available in new money long-term debt financing authority from the ICC as of September 30, 2019 and has an expiration date of August 1, 2021.

Contractual Obligations and Off-Balance Sheet Arrangements
Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 2018 Form 10-K.
Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
For an in-depth discussion of the Registrants' contractual obligations and off-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in the Exelon 2018 Form 10-K.

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

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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, 2018 to September 30, 2019. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all NPNS contracts and does not segregate proprietary trading activity. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of September 30, 2019 and December 31, 2018.
 
Exelon
 
Generation
 
ComEd
Total mark-to-market energy contract net assets (liabilities) at December 31, 2018(a)
$
299

 
$
548

 
$
(249
)
Total change in fair value during 2019 of contracts recorded in results of operations
(273
)
 
(273
)
 
—

Reclassification to realized of contracts recorded in results of operations
215

 
215

 
—

Changes in fair value — recorded through regulatory assets and liabilities(b)
(31
)
 
—

 
(31
)
Changes in allocated collateral
364

 
364

 
—

Net option premium paid/(received)
(13
)
 
(13
)
 
—

Option premium amortization
(21
)
 
(21
)
 
—

Upfront payments and amortizations(c)
(73
)
 
(73
)
 
—

Total mark-to-market energy contract net assets (liabilities) at September 30, 2019(a)
$
467

 
$
747

 
$
(280
)
_________
(a)
Amounts are shown net of collateral paid to and received from counterparties.
(b)
For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of September 30, 2019, ComEd recorded a regulatory liability of $280 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the nine months ended September 30, 2019, ComEd recorded $31 million of decreases in fair value and an increase for realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)
Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations
Fair Values
The following tables present maturity and source of fair value for Exelon, Generation and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 9 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

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Exelon
 
Maturities Within
 
Total Fair
Value
 
2019
 
2020
 
2021
 
2022
 
2023
 
2024 and Beyond
 
Normal Operations, Commodity derivative contracts(a)(b):
 
 
 
 
 
 
 
 
 
 
 
 
 
Actively quoted prices (Level 1)
$
(22
)
 
$
(105
)
 
$
(25
)
 
$
(13
)
 
$
9

 
$
9

 
$
(147
)
Prices provided by external sources (Level 2)
76

 
(1
)
 
47

 
(10
)
 
—

 
—

 
112

Prices based on model or other valuation methods (Level 3)(c)
65

 
442

 
116

 
33

 
(6
)
 
(148
)
 
502

Total
$
119

 
$
336

 
$
138

 
$
10

 
$
3

 
$
(139
)
 
$
467

_________
(a)
Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.
(b)
Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $721 million at September 30, 2019.
(c)
Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Generation
 
Maturities Within
 
Total Fair
Value
 
2019
 
2020
 
2021
 
2022
 
2023
 
2024 and Beyond
 
Normal Operations, Commodity derivative contracts(a)(b): 
 
 
 
 
 
 
 
 
 
 
 
 
 
Actively quoted prices (Level 1)
$
(22
)
 
$
(105
)
 
$
(25
)
 
$
(13
)
 
$
9

 
$
9

 
$
(147
)
Prices provided by external sources (Level 2)
76

 
(1
)
 
47

 
(10
)
 
—

 
—

 
112

Prices based on model or other valuation methods (Level 3)
75

 
469

 
143

 
60

 
21

 
14

 
782

Total
$
129

 
$
363

 
$
165

 
$
37

 
$
30

 
$
23

 
$
747

_________
(a)
Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.
(b)
Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $721 million at September 30, 2019.
ComEd
 
Maturities Within
 
Total Fair
Value
 
2019
 
2020
 
2021
 
2022
 
2023
 
2024 and Beyond
 
Commodity derivative contracts(a): 
 
 
 
 
 
 
 
 
 
 
 
 
 
Prices based on model or other valuation methods (Level 3)
$
(10
)
 
$
(27
)
 
$
(27
)
 
$
(27
)
 
$
(27
)
 
$
(162
)
 
$
(280
)
_________
(a)
Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the

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fair value of contracts at the reporting date. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for detailed discussion of credit risk.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchases and normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2019. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs and commodity exchanges, which are discussed below. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $68 million, $30 million, $32 million, $39 million, $15 million and $8 million as of September 30, 2019, respectively.
Rating as of September 30, 2019
 
Total  Exposure Before Credit Collateral
 
Credit
Collateral(a)
 
Net
Exposure
 
Number of
Counterparties
Greater than 10%
of Net Exposure
 
Net Exposure of
Counterparties
Greater than
10% of Net
Exposure
Investment grade
 
$
693

 
$
10

 
$
683

 
$
—

 
$
—

Non-investment grade
 
74

 
38

 
36

 


 


No external ratings
 
 
 
 
 
 
 
 
 
 
Internally rated — investment grade
 
297

 
1

 
296

 


 


Internally rated — non-investment grade
 
175

 
24

 
151

 


 


Total
 
$
1,239

 
$
73

 
$
1,166

 
$
—

 
$
—

 
 
Maturity of Credit Risk Exposure
Rating as of September 30, 2019
 
Less than
2 Years
 
2-5 Years
 
Exposure
Greater than
5 Years
 
Total Exposure
Before Credit
Collateral
Investment grade
 
$
649

 
$
38

 
$
6

 
$
693

Non-investment grade
 
76

 
(2
)
 
—

 
74

No external ratings
 
 
 
 
 
 
 
 
Internally rated — investment grade
 
234

 
35

 
28

 
297

Internally rated — non-investment grade
 
148

 
16

 
11

 
175

Total
 
$
1,107

 
$
87

 
$
45

 
$
1,239

Net Credit Exposure by Type of Counterparty
 
As of
September 30, 2019
Financial institutions
 
$
1

Investor-owned utilities, marketers, power producers
 
875

Energy cooperatives and municipalities
 
255

Other
 
35

Total
 
$
1,166

_________
(a)
As of September 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $18 million of cash and $55 million of letters of credit.

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

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investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $570 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Liquidity and Capital Resources section of ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information of equity price risk as a result of the current capital and credit market conditions.
Item 4.    Controls and Procedures
During the third quarter of 2019, each of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by all Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to Exelon’s management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of September 30, 2019, the principal executive officer and principal financial officer of each of Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. All Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There have been no changes in internal control over financial reporting that occurred during the third quarter of 2019 that have materially affected, or are reasonably likely to materially affect, any of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and ACE’s internal control over financial reporting.
PART II — OTHER INFORMATION
Item 1.    Legal Proceedings
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s 2018 Form 10-K and (b) Notes 6 — Regulatory Matters and 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.
Item 1A.    Risk Factors
Risks Related to Exelon
At September 30, 2019, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2018 Form 10-K in ITEM 1A. RISK FACTORS.
Item 4.    Mine Safety Disclosures
All Registrants
Not applicable to the Registrants.

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Item 5.    Other Information
Generation - Second Amended and Restated Operating Agreement
On October 30, 2019, Exelon, as sole member of Generation, executed the Second Amended and Restated Operating Agreement of Generation solely to update certain administrative provisions.  This summary is qualified by reference to the complete text of the Second Amended and Restated Operating Agreement of Generation, attached as Exhibit 3.1 to this Report. 

Item 6.    Exhibits
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis and the relevant Registrant agrees to furnish a copy of any such instrument to the Commission upon request.
Exhibit
No.
Description
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
101.INS
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
XBRL Taxonomy Extension Schema Document.
 
 
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document.
 
 
101.LAB
XBRL Taxonomy Extension Label Linkbase Document.
 
 
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
*Filed herewith

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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2019 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 September 30, 2019 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)
 
 
October 31, 2019

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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)
 
 
October 31, 2019

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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)
 
 
October 31, 2019

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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/    SCOTT A. BAILEY
 
 
Scott A. Bailey
 
 
Vice President and Controller
(Principal Accounting Officer)
 
 
October 31, 2019


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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/    CALVIN G. BUTLER, JR.
 
/s/    DAVID M. VAHOS
Calvin G. Butler, Jr.
 
David M. Vahos
Chief Executive Officer
(Principal Executive Officer)
 
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
 
 
 
 /s/ ANDREW W. HOLMES
 
 
Andrew W. Holmes
 
 
Vice President and Controller
(Principal Accounting Officer)
 
 
October 31, 2019


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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/ ROBERT M. AIKEN
 
 
Robert M. Aiken
 
 
Vice President and Controller
(Principal Accounting Officer)
 
 
October 31, 2019


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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/ ROBERT M. AIKEN
 
 
Robert M. Aiken
 
 
Vice President and Controller
(Principal Accounting Officer)
 
 
October 31, 2019


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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/ ROBERT M. AIKEN
 
 
Robert M. Aiken
 
 
Vice President and Controller
(Principal Accounting Officer)
 
 
October 31, 2019


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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/ ROBERT M. AIKEN
 
 
Robert M. Aiken
 
 
Vice President and Controller
(Principal Accounting Officer)
 
 
October 31, 2019

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