EXELON CORP - Interim / Quarterly Report 2019

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

☐ 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

GLOSSARY OF TERMS AND ABBREVIATIONS		Page No. — 4
FILING FORMAT		8
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION		8
WHERE TO FIND MORE INFORMATION		8
PART I.	FINANCIAL INFORMATION	9
ITEM 1.	FINANCIAL STATEMENTS	9
	Exelon Corporation
	Consolidated Statements of Operations and Comprehensive Income	10
	Consolidated Statements of Cash Flows	11
	Consolidated Balance Sheets	12
	Consolidated Statements of Changes in Shareholders’ Equity	14
	Exelon Generation Company, LLC
	Consolidated Statements of Operations and Comprehensive Income	16
	Consolidated Statements of Cash Flows	17
	Consolidated Balance Sheets	18
	Consolidated Statements of Changes in Equity	20
	Commonwealth Edison Company
	Consolidated Statements of Operations and Comprehensive Income	22
	Consolidated Statements of Cash Flows	23
	Consolidated Balance Sheets	24
	Consolidated Statements of Changes in Shareholders' Equity	26
	PECO Energy Company
	Consolidated Statements of Operations and Comprehensive Income	27
	Consolidated Statements of Cash Flows	28
	Consolidated Balance Sheets	29
	Consolidated Statements of Changes in Shareholder's Equity	31
	Baltimore Gas and Electric Company
	Statements of Operations and Comprehensive Income	32
	Statements of Cash Flows	33
	Balance Sheets	34
	Statements of Changes in Shareholder's Equity	36
	Pepco Holdings LLC
	Consolidated Statements of Operations and Comprehensive Income	37
	Consolidated Statements of Cash Flows	38
	Consolidated Balance Sheets	39
	Consolidated Statements of Changes in Equity	41

	Page No.
Potomac Electric Power Company
Statements of Operations and Comprehensive Income	42
Statements of Cash Flows	43
Balance Sheets	44
Statements of Changes in Shareholder's Equity	46
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income	47
Statements of Cash Flows	48
Balance Sheets	49
Statements of Changes in Shareholder’s Equity	51
Atlantic City Electric Company
Consolidated Statements of Operations and Comprehensive Income	52
Consolidated Statements of Cash Flows	53
Consolidated Balance Sheets	54
Consolidated Statements of Changes in Shareholder’s Equity	56
Combined Notes to Consolidated Financial Statements	57
1. Significant Accounting Policies	57
2. Variable Interest Entities	59
3. Mergers, Acquisitions and Dispositions	63
4. Revenue from Contracts with Customers	64
5. Leases	65
6. Regulatory Matters	69
7. Asset Impairments	75
8. Early Plant Retirements	76
9. Fair Value of Financial Assets and Liabilities	78
10. Derivative Financial Instruments	89
11. Debt and Credit Agreements	96
12. Income Taxes	98
13. Nuclear Decommissioning	101
14. Retirement Benefits	103
15. Changes in Accumulated Other Comprehensive Income	105
16. Commitments and Contingencies	106
17. Supplemental Financial Information	113
18. Segment Information	119

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	Page No. — 135
	Exelon Corporation	135
	Executive Overview	135
	Financial Results of Operations	136
	Significant 2019 Transactions and Developments	140
	Other Key Business Drivers and Management Strategies	143
	Critical Accounting Policies and Estimates	146
	Results of Operations By Registrant	146
	Exelon Generation Company, LLC	147
	Commonwealth Edison Company	154
	PECO Energy Company	157
	Baltimore Gas and Electric Company	161
	Pepco Holdings LLC	164
	Potomac Electric Power Company	165
	Delmarva Power & Light Company	168
	Atlantic City Electric Company	173
	Liquidity and Capital Resources	177
	Contractual Obligations and Off-Balance Sheet Arrangements	184
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	185
ITEM 4.	CONTROLS AND PROCEDURES	190
PART II.	OTHER INFORMATION	190
ITEM 1.	LEGAL PROCEEDINGS	190
ITEM 1A.	RISK FACTORS	190
ITEM 4.	MINE SAFETY DISCLOSURES	190
ITEM 5.	OTHER INFORMATION	191
ITEM 6.	EXHIBITS	191
SIGNATURES		194
	Exelon Corporation	194
	Exelon Generation Company, LLC	195
	Commonwealth Edison Company	196
	PECO Energy Company	197
	Baltimore Gas and Electric Company	198
	Pepco Holdings LLC	199
	Potomac Electric Power Company	200
	Delmarva Power & Light Company	201
	Atlantic City Electric Company	202

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

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

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

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

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.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

(In millions, except per share data)	Three Months Ended September 30, — 2019		2018		Nine Months Ended September 30, — 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

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)	Nine Months Ended September 30, — 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

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

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

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

(In millions, shares in thousands)	Nine Months Ended September 30, 2019 — 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

Table of Contents

(In millions, shares in thousands)	Nine Months Ended September 30, 2018 — 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

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

(In millions)	Three Months Ended September 30, — 2019		2018		Nine Months Ended September 30, — 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

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)	Nine Months Ended September 30, — 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

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

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

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

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

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

(In millions)	Three Months Ended September 30, — 2019		2018		Nine Months Ended September 30, — 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

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)	Nine Months Ended September 30, — 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

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

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

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

(In millions)	Nine Months Ended September 30, 2019 — 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

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

(In millions)	Three Months Ended September 30, — 2019		2018		Nine Months Ended September 30, — 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

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)	Nine Months Ended September 30, — 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

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

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

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)

(In millions)	Nine months ended September 30, 2019 — 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

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

(In millions)	Three Months Ended September 30, — 2019		2018		Nine Months Ended September 30, — 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

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)	Nine Months Ended September 30, — 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

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

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

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

(In millions)	Nine Months Ended September 30, 2019 — 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

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

(In millions)	Three Months Ended September 30, — 2019		2018		Nine Months Ended September 30, — 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

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)	Nine Months Ended September 30, — 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

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

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

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

(In millions)	Nine Months Ended September 30, 2019 — 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

(In millions)	Nine Months Ended September 30, 2018 — 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

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

(In millions)	Three Months Ended September 30, — 2019		2018		Nine Months Ended September 30, — 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

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)	Nine Months Ended September 30, — 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

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

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

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

(In millions)	Nine Months Ended September 30, 2019 — 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

(In millions)	Nine Months Ended September 30, 2018 — 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

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

(In millions)	Three Months Ended September 30, — 2019		2018		Nine Months Ended September 30, — 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

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)	Nine Months Ended September 30, — 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

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

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

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

(In millions)	Nine Months Ended September 30, 2019 — 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

(In millions)	Nine Months Ended September 30, 2018 — 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

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

(In millions)	Three Months Ended September 30, — 2019		2018		Nine Months Ended September 30, — 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

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In millions)	Nine Months Ended September 30, — 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

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

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

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

(In millions)	Nine Months Ended September 30, 2019 — 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

(In millions)	Nine Months Ended September 30, 2018 — 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

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

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.

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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.

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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 — Exelon	Generation	PHI (a)	ACE	December 31, 2018 — 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 — Commercial Agreement VIEs	Equity Investment VIEs	Total	December 31, 2018 — 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 value s. 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 — Exelon		Generation		Contract Liabilities — 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.

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

Note 6 — Regulatory Matters

at 55 % . As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50 % , inclusive of a 50-basis-point incentive adder for being a member of a RTO.

Pending Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. PECO’s initial formula rate filing included a requested increase of $ 22 million to PECO’s annual transmission revenue requirement, which reflected a ROE of 11 % , inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures.

Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $ 6 million and an increase of $ 8 million , respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.

On July 22, 2019, PECO and other parties filed with FERC a settlement agreement, which includes a ROE of 10.35 % , inclusive of a 50 basis point adder for being a member of a RTO. The settlement 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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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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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Asset Impairments

Antelope Valley Solar Facility

Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of 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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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 8 — Early Plant Retirements

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

Income statement expense (pre-tax)	Three Months Ended September 30, — 2019	2018	Nine Months Ended September 30, — 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)

E xelon 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 — Carrying Amount	Fair Value			December 31, 2018 — 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

As of September 30, 2019	Exelon — Level 1	Level 2	Level 3	Not subject to leveling	Total	Generation — 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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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

As of September 30, 2019	Exelon — Level 1		Level 2		Level 3		Not subject to leveling	Total		Generation — 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

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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

As of December 31, 2018	Exelon — Level 1		Level 2		Level 3		Not subject to leveling	Total		Generation — 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

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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

As of December 31, 2018	Exelon — Level 1		Level 2		Level 3		Not subject to leveling	Total		Generation — 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.

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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

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

As of September 30, 2019	ComEd — Level 1	Level 2		Level 3		Total		PECO — Level 1	Level 2		Level 3	Total		BGE — 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

As of December 31, 2018	ComEd — Level 1	Level 2		Level 3		Total		PECO — Level 1	Level 2		Level 3	Total		BGE — 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

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

PHI	As of September 30, 2019 — Level 1	Level 2		Level 3	Total		As of December 31, 2018 — 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

As of September 30, 2019	Pepco — Level 1	Level 2		Level 3	Total		DPL — Level 1	Level 2	Level 3	Total	ACE — 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

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

As of December 31, 2018	Pepco — Level 1	Level 2		Level 3	Total		DPL — Level 1	Level 2		Level 3	Total		ACE — 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 :

Three Months Ended September 30, 2019	Exelon — Total		Generation — NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		ComEd — Mark-to-Market Derivatives			PHI and Pepco — 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	)	$ —			$ —	$ —

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

Nine Months Ended September 30, 2019	Exelon — Total		Generation — NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		ComEd — Mark-to-Market Derivatives			PHI and Pepco — 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.

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

Three Months Ended September 30, 2018	Exelon — Total		Generation — NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		ComEd — Mark-to-Market Derivatives			PHI and Pepco — 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	)	$ —			$ —	$ —

Nine Months Ended September 30, 2018	Exelon — Total		Generation — NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		ComEd — Mark-to-Market Derivatives			PHI and Pepco — 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 .

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 — Operating Revenues		Purchased Power and Fuel		Operating and Maintenance	Other, net	Generation — Operating Revenues		Purchased Power and Fuel		Other, net	PHI and Pepco — 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 — Operating Revenues		Purchased Power and Fuel		Operating and Maintenance	Other, net		Generation — Operating Revenues		Purchased Power and Fuel		Other, net		PHI and Pepco — 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	)	—

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 table below discloses the significant inputs to the forward curve used to value these positions.

Type of trade — Mark-to-market derivatives — Economic Hedges (Exelon and Generation) (a)(b)	Fair Value at September 30, 2019 — $ 411		Fair Value at December 31, 2018 — $ 443		Valuation Technique — Discounted Cash Flow	Unobservable Input — Forward power price	2019 Range — $ 11	-	$ 167	2018 Range — $ 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)	9 x	-	10 x	10 x	-	11 x
						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.

Table of Contents

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.

Table of Contents

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.

Table of Contents

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 — Derivatives	Exelon — Total Derivatives		Generation — Economic Hedges		Proprietary Trading		Collateral (a)(b)	Netting (a)		Subtotal		ComEd — 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 — Description	Exelon — Total Derivatives		Generation — Economic Hedges		Proprietary Trading		Collateral (a)(b)	Netting (a)		Subtotal		ComEd — 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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(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, — 2019		2018	Nine Months Ended September 30, — 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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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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(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 — Gross fair value of derivative contracts containing this feature (a)	September 30, 2019 — $ ( 1,249	)	December 31, 2018 — $ ( 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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(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 .

Commercial Paper Issuer	Outstanding Commercial Paper as of — September 30, 2019	December 31, 2018	Average Interest Rate on Commercial Paper Borrowings as of — 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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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.

100

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 12 — Income Taxes

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

Settlement of Income Tax Audits, Refund Claims, and Litigation

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)	$
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, — 2019		2018		OPEB Three Months Ended September 30, — 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, — 2019		2018		OPEB Nine Months Ended September 30, — 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.

Pension and OPEB Costs	Three Months Ended September 30, — 2019	2018	Nine Months Ended September 30, — 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.

Savings Plan Matching Contributions	Three Months Ended September 30, — 2019	2018	Nine Months Ended September 30, — 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 — Beginning balance	Losses on Cash Flow Hedges — $ ( 2	)	Pension and Non-Pension Postretirement Benefit Plan Items (a) — $ ( 2,957	)	Foreign Currency Items — $ ( 29	)	AOCI of Investments in Unconsolidated Affiliates (b) — $ ( 2	Total — $ ( 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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(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Changes in Accumulated Other Comprehensive Income

Nine Months Ended September 30, 2019 — Beginning balance	Losses on Cash Flow Hedges — $ ( 2	)	Pension and Non-Pension Postretirement Benefit Plan Items (a) — $ ( 2,960	)	Foreign Currency Items — $ ( 33	)	AOCI of Investments in Unconsolidated Affiliates (b) — $ —		Total — $ ( 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 — Beginning balance	Gains (Losses) on Cash Flow Hedges — $ ( 14	)	Unrealized gains (losses) on Marketable Securities — $ 10		Pension and Non-Pension Postretirement Benefit Plan Items (a) — $ ( 2,998	)	Foreign Currency Items — $ ( 23	)	AOCI of Investments in Unconsolidated Affiliates (b) — $ ( 1	Total — $ ( 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, — 2019		2018		Nine Months Ended September 30, — 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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(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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(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 follow s:

	Total	Expiration within — 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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(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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(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 — Total environmental investigation and remediation liabilities	Portion of total related to MGP investigation and remediation	December 31, 2018 — 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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(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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(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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(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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(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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(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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(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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(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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(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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(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 — RNF from external customers (a)	Intersegment RNF		Total RNF	Three Months Ended September 30, 2018 — 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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(Dollars in millions, except per share data, unless otherwise noted)

Note 18 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):

Revenues from contracts with customers	Three Months Ended September 30, 2019 — 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

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

Note 18 — Segment Information

Revenues from contracts with customers	Three Months Ended September 30, 2018 — 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 .

(d) Includes operating revenues from affiliates of less than $1 million and $ 4 million at PECO and BGE, respectively, in 2019 and less than $1 million and $ 5 million at PECO and BGE, respectively, in 2018 .

(e) Includes late payment charge revenues.

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(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

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(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.

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(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

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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

(b) Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.

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.

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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 — RNF from external customers (a)	Intersegment RNF		Total RNF	Nine Months Ended September 30, 2018 — 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.

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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):

Revenues from contracts with customers	Nine Months Ended September 30, 2019 — 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

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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 from contracts with customers	Nine Months Ended September 30, 2018 — 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 .

(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 in creased 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 in creased 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:

• 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 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;

• 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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Generation

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:

Mid-Atlantic	Increase/ (Decrease) — $ (74	)	Three Months Ended September 30, 2019 — • 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	Increase/ (Decrease) — $ (325	)	Nine Months Ended September 30, 2019 — • 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	)	• t he 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, — 2019	2018	Nine Months Ended September 30, — 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 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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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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, — 2019	2018	Nine Months Ended September 30, — 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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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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The changes in RNF consisted of the following:

	Three Months Ended September 30, 2019 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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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The changes in Operating and maintenance expense consisted of the following:

	Three Months Ended September 30, 2019 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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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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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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 — Three Months Ended September 30,	2019	2018	Normal	% Change — 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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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	)%

Number of Electric Customers	As of September 30, — 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 %

Number of Natural Gas Customers	As of September 30, — 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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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 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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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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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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.

Number of Electric Customers	As of September 30, — 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

Number of Natural Gas Customers	As of September 30, — 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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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 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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 — Increase (Decrease)	Nine Months Ended September 30, 2019 — 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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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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The changes in RNF consisted of the following:

	Three Months Ended September 30, 2019 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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.

Number of Electric Customers	As of September 30, — 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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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 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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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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.

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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 — Three Months Ended September 30,	2019	2018	Normal	% Change — 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 — Three Months Ended September 30,	2019	2018	Normal	% Change — 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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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	)%

Number of Total Electric Customers (Maryland and Delaware)	As of September 30, — 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	%

Number of Delaware Natural Gas Customers	As of September 30, — 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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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 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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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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.

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ACE

The changes in RNF consisted of the following:

	Three Months Ended September 30, 2019 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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 — Three Months Ended September 30,	2019	2018	Normal	% Change — 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

Number of Electric Customers	As of September 30, — 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 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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 — Increase (Decrease)		Nine Months Ended September 30, 2019 — 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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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 base d 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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Increase (Decrease) in cash flows from operating activities — Net income	Exelon — $ 241		Generation — $ 117		ComEd — $ 21		PECO — $ 74		BGE — $ 19		PHI — $ 76		Pepco — $ 43		DPL — $ 26		ACE — $ 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 procuremen t 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 — Contributed (Borrowed)	During the Three Months Ended September 30, 2019 — Maximum Contributed	Maximum Borrowed		As of September 30, 2019 — 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 — Contributed (Borrowed)	During the Three Months Ended September 30, 2019 — Maximum Contributed	Maximum Borrowed		As of September 30, 2019 — 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 .

Total mark-to-market energy contract net assets (liabilities) at December 31, 2018 (a)	Exelon — $ 299		Generation — $ 548		ComEd — $ (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 — 2019		2020		2021		2022		2023	2024 and Beyond	Total Fair Value
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	$ —	$ —

Rating as of September 30, 2019	Maturity of Credit Risk Exposure — 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
3.1 *	Second Amended and Restated Operating Agreement of Exelon Generation Company, LLC
4.1	One Hundred and Seventeenth Supplemental Indenture dated as of August 15, 2019 from PECO Energy Company to U.S. Bank National Association, as trustee (File No. 000-16844, Form 8-K dated September 10, 2019)
4.2	Indenture, dated as of September 1, 2019, between Baltimore Gas and Electric Company and U.S. Bank National Association, as trustee (File No. 001-01910, Form 8-K dated September 12, 2019, Exhibit 4.1)
10.1 *	Exelon Corporation Non-Employee Director Deferred Stock Unit Plan, as amended and restated effective September 25, 2019.
10.2 *	Amended Form of Restricted Stock Award Agreement under Exelon Corporation Long-Term Incentive Plan
10.3 *	Exelon Corporation Employee Stock Purchase Plan, as amended and restated effective September 25, 2019.
10.4 *	Exelon Corporation Employee Stock Purchase Plan for Unincorporated Subsidiaries, as amended and restated effective September 25, 2019.
10.5 *	Exelon Corporation Stock Deferral Plan, as amended and restated effective September 25, 2019.
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:

31-1	— Filed by Christopher M. Crane for Exelon Corporation
31-2	— Filed by Joseph Nigro for Exelon Corporation
31-3	— Filed by Kenneth W. Cornew for Exelon Generation Company, LLC
31-4	— Filed by Bryan P. Wright for Exelon Generation Company, LLC
31-5	— Filed by Joseph Dominguez for Commonwealth Edison Company
31-6	— Filed by Jeanne M. Jones for Commonwealth Edison Company
31-7	— Filed by Michael A. Innocenzo for PECO Energy Company
31-8	— Filed by Robert J. Stefani for PECO Energy Company
31-9	— Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company
31-10	— Filed by David M. Vahos for Baltimore Gas and Electric Company
31-11	— Filed by David M. Velazquez for Pepco Holdings LLC
31-12	— Filed by Phillip S. Barnett for Pepco Holdings LLC
31-13	— Filed by David M. Velazquez for Potomac Electric Power Company
31-14	— Filed by Phillip S. Barnett for Potomac Electric Power Company
31-15	— Filed by David M. Velazquez for Delmarva Power & Light Company
31-16	— Filed by Phillip S. Barnett for Delmarva Power & Light Company
31-17	— Filed by David M. Velazquez for Atlantic City Electric Company
31-18	— Filed by Phillip S. Barnett for Atlantic City Electric Company

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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:

32-1	— Filed by Christopher M. Crane for Exelon Corporation
32-2	— Filed by Joseph Nigro for Exelon Corporation
32-3	— Filed by Kenneth W. Cornew for Exelon Generation Company, LLC
32-4	— Filed by Bryan P. Wright for Exelon Generation Company, LLC
32-5	— Filed by Joseph Dominguez for Commonwealth Edison Company
32-6	— Filed by Jeanne M. Jones for Commonwealth Edison Company
32-7	— Filed by Michael A. Innocenzo for PECO Energy Company
32-8	— Filed by Robert J. Stefani for PECO Energy Company
32-9	— Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company
32-10	— Filed by David M. Vahos for Baltimore Gas and Electric Company
32-11	— Filed by David M. Velazquez for Pepco Holdings LLC
32-12	— Filed by Phillip S. Barnett for Pepco Holdings LLC
32-13	— Filed by David M. Velazquez for Potomac Electric Power Company
32-14	— Filed by Phillip S. Barnett for Potomac Electric Power Company
32-15	— Filed by David M. Velazquez for Delmarva Power & Light Company
32-16	— Filed by Phillip S. Barnett for Delmarva Power & Light Company
32-17	— Filed by David M. Velazquez for Atlantic City Electric Company
32-18	— Filed by Phillip S. Barnett for Atlantic City Electric Company

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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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