Peco Energy 10-Q 2020 Q2 Quarterly report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2020

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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

Securities registered pursuant to Section 12(b) of the Act:

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Exelon Corporation	Large Accelerated Filer	x	Accelerated Filer	☐	Non-accelerated Filer	☐	Smaller Reporting Company	☐	Emerging Growth Company	☐
Exelon Generation Company, LLC	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Commonwealth Edison Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
PECO Energy Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Baltimore Gas and Electric Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Pepco Holdings LLC	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Potomac Electric Power Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Delmarva Power & Light Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Atlantic City Electric Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐

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

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

The number of shares outstanding of each registrant’s common stock as of June 30, 2020 was:

Exelon Corporation Common Stock, without par value	974,503,895
Exelon Generation Company, LLC	not applicable
Commonwealth Edison Company Common Stock, $12.50 par value	127,021,354
PECO Energy Company Common Stock, without par value	170,478,507
Baltimore Gas and Electric Company Common Stock, without par value	1,000
Pepco Holdings LLC	not applicable
Potomac Electric Power Company Common Stock, $0.01 par value	100
Delmarva Power & Light Company Common Stock, $2.25 par value	1,000
Atlantic City Electric Company Common Stock, $3.00 par value	8,546,017

TABLE OF CONTENTS

		Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS		4
FILING FORMAT		8
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION		8
WHERE TO FIND MORE INFORMATION		8
PART I.	FINANCIAL INFORMATION	9
ITEM 1.	FINANCIAL STATEMENTS	9
	Exelon Corporation
	Consolidated Statements of Operations and Comprehensive Income	10
	Consolidated Statements of Cash Flows	11
	Consolidated Balance Sheets	12
	Consolidated Statements of Changes in Shareholders’ Equity	14
	Exelon Generation Company, LLC
	Consolidated Statements of Operations and Comprehensive Income	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	21
	Consolidated Statements of Cash Flows	22
	Consolidated Balance Sheets	23
	Consolidated Statements of Changes in Shareholders' Equity	25
	PECO Energy Company
	Consolidated Statements of Operations and Comprehensive Income	26
	Consolidated Statements of Cash Flows	27
	Consolidated Balance Sheets	28
	Consolidated Statements of Changes in Shareholder's Equity	30
	Baltimore Gas and Electric Company
	Statements of Operations and Comprehensive Income	31
	Statements of Cash Flows	32
	Balance Sheets	33
	Statements of Changes in Shareholder's Equity	35
	Pepco Holdings LLC
	Consolidated Statements of Operations and Comprehensive Income	36
	Consolidated Statements of Cash Flows	37
	Consolidated Balance Sheets	38
	Consolidated Statements of Changes in Equity	40

1

	Page No.
Potomac Electric Power Company
Statements of Operations and Comprehensive Income	41
Statements of Cash Flows	42
Balance Sheets	43
Statements of Changes in Shareholder's Equity	45
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income	46
Statements of Cash Flows	47
Balance Sheets	48
Statements of Changes in Shareholder’s Equity	50
Atlantic City Electric Company
Consolidated Statements of Operations and Comprehensive Income	51
Consolidated Statements of Cash Flows	52
Consolidated Balance Sheets	53
Consolidated Statements of Changes in Shareholder’s Equity	55
Combined Notes to Consolidated Financial Statements
1. Significant Accounting Policies	56
2. Regulatory Matters	58
3. Revenue from Contracts with Customers	64
4. Segment Information	66
5. Accounts Receivable	81
6. Early Plant Retirements	84
7. Nuclear Decommissioning	87
8. Asset Impairments	88
9. Income Taxes	89
10. Retirement Benefits	93
11. Derivative Financial Instruments	95
12. Debt and Credit Agreements	101
13. Fair Value of Financial Assets and Liabilities	104
14. Commitments and Contingencies	117
15. Changes in Accumulated Other Comprehensive Income	125
16. Variable Interest Entities	126
17. Supplemental Financial Information	131
18. Related Party Transactions	137
19. Subsequent Events	140

2

		Page No.
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	141
	Exelon Corporation	141
	Executive Overview	141
	Financial Results of Operations	143
	Significant 2020 Transactions and Developments	147
	Other Key Business Drivers and Management Strategies	149
	Critical Accounting Policies and Estimates	151
	Results of Operations By Registrant	151
	Exelon Generation Company, LLC	152
	Commonwealth Edison Company	159
	PECO Energy Company	162
	Baltimore Gas and Electric Company	166
	Pepco Holdings LLC	169
	Potomac Electric Power Company	170
	Delmarva Power & Light Company	173
	Atlantic City Electric Company	177
	Liquidity and Capital Resources	181
	Contractual Obligations and Off-Balance Sheet Arrangements	188
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	189
ITEM 4.	CONTROLS AND PROCEDURES	194
PART II.	OTHER INFORMATION	194
ITEM 1.	LEGAL PROCEEDINGS	194
ITEM 1A.	RISK FACTORS	194
ITEM 4.	MINE SAFETY DISCLOSURES	195
ITEM 6.	EXHIBITS	195
SIGNATURES		199
	Exelon Corporation	199
	Exelon Generation Company, LLC	200
	Commonwealth Edison Company	201
	PECO Energy Company	202
	Baltimore Gas and Electric Company	203
	Pepco Holdings LLC	204
	Potomac Electric Power Company	205
	Delmarva Power & Light Company	206
	Atlantic City Electric Company	207

3

GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon	Exelon Corporation
Generation	Exelon Generation Company, LLC
ComEd	Commonwealth Edison Company
PECO	PECO Energy Company
BGE	Baltimore Gas and Electric Company
Pepco Holdings or PHI	Pepco Holdings LLC (formerly Pepco Holdings, Inc.)
Pepco	Potomac Electric Power Company
DPL	Delmarva Power & Light Company
ACE	Atlantic City Electric Company
Registrants	Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively
Utility Registrants	ComEd, PECO, BGE, Pepco, DPL and ACE, collectively
ACE Funding or ATF	Atlantic City Electric Transition Funding LLC
Antelope Valley	Antelope Valley Solar Ranch One
BSC	Exelon Business Services Company, LLC
CENG	Constellation Energy Nuclear Group, LLC
Constellation	Constellation Energy Group, Inc.
EGR IV	ExGen Renewables IV, LLC
EGRP	ExGen Renewables Partners, LLC
Exelon Corporate	Exelon in its corporate capacity as a holding company
FitzPatrick	James A. FitzPatrick nuclear generating station
NER	NewEnergy Receivables LLC
PCI	Potomac Capital Investment Corporation and its subsidiaries
PECO Trust III	PECO Capital Trust III
PECO Trust IV	PECO Energy Capital Trust IV
Pepco Energy Services	Pepco Energy Services, Inc. and its subsidiaries
PHI Corporate	PHI in its corporate capacity as a holding company
PHISCO	PHI Service Company
SolGen	SolGen, LLC
TMI	Three Mile Island nuclear facility

4

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note "—" of the 2019 Form 10-K	Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2019 Annual Report on Form 10-K
AEC	Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source
AESO	Alberta Electric Systems Operator
AFUDC	Allowance for Funds Used During Construction
AMI	Advanced Metering Infrastructure
AOCI	Accumulated Other Comprehensive Income (Loss)
ARC	Asset Retirement Cost
ARO	Asset Retirement Obligation
BGS	Basic Generation Service
CBA	Collective Bargaining Agreement
CERCLA	Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CES	Clean Energy Standard
Clean Water Act	Federal Water Pollution Control Amendments of 1972, as amended
CODM	Chief operating decision maker(s)
D.C. Circuit Court	United States Court of Appeals for the District of Columbia Circuit
DC PLUG	District of Columbia Power Line Undergrounding Initiative
DCPSC	Public Service Commission of the District of Columbia
DOE	United States Department of Energy
DOEE	Department of Energy & Environment
DOJ	United States Department of Justice
DPP	Deferred Purchase Price
DPSC	Delaware Public Service Commission
EDF	Electricite de France SA and its subsidiaries
EIMA	Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EPA	United States Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas
FASB	Financial Accounting Standards Board
FEJA	Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC	Federal Energy Regulatory Commission
FRCC	Florida Reliability Coordinating Council
FRR	Fixed Resource Requirement
GAAP	Generally Accepted Accounting Principles in the United States
GCR	Gas Cost Rate
GSA	Generation Supply Adjustment
IBEW	International Brotherhood of Electrical Workers
ICC	Illinois Commerce Commission
ICE	Intercontinental Exchange

5

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

6

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
RNF	Revenues Net of Purchased Power and Fuel Expense
Regulatory Agreement Units	Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RFP	Request for Proposal
Rider	Reconcilable Surcharge Recovery Mechanism
RMC	Risk Management Committee
ROE	Return on equity
ROU	Right-of-use
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Services
SEC	United States Securities and Exchange Commission
SERC	SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SNF	Spent Nuclear Fuel
SOS	Standard Offer Service
SPFPA	International Union, Security, Police and Fire Professionals of America
TCJA	Tax Cuts and Jobs Act
Transition Bonds	Transition Bonds issued by ACE Funding
VIE	Variable Interest Entity
WECC	Western Electric Coordinating Council
ZEC	Zero Emission Credit, or Zero Emission Certificate
ZES	Zero Emission Standard

7

FILING FORMAT

This combined Form 10-Q is being filed separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including among others those related to the expected or potential impact of the novel coronavirus (COVID-19) pandemic, and the related responses of various governments and regulatory bodies, our customers, and the company, on our business, financial condition and results of operations; any such forward-looking statements, whether concerning the COVID-19 pandemic or otherwise, involve risks, assumptions and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic and financial performance, are intended to identify such forward-looking statements.

The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the Registrants' combined 2019 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors; (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, ITEM 1. Financial Statements: Note 14, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.

Investors are cautioned not to place undue reliance on these forward-looking statements, whether written or oral, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

WHERE TO FIND MORE INFORMATION

The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and the Registrants' website at www.exeloncorp.com. Information contained on the Registrants' website shall not be deemed incorporated into, or to be a part of, this Report.

8

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

9

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions, except per share data)	2020			2019			2020			2019
Operating revenues
Competitive businesses revenues	$	3,611		$	3,959		$	8,014		$	8,938
Rate-regulated utility revenues	3,832			3,743			8,108			8,247
Revenues from alternative revenue programs	(122		)	(13		)	(55		)	(19		)
Operating revenue from affiliates	1			—			2			—
Total operating revenues	7,322			7,689			16,069			17,166
Operating expenses
Competitive businesses purchased power and fuel	1,945			2,289			4,655			5,493
Rate-regulated utility purchased power and fuel	979			936			2,136			2,285
Operating and maintenance	2,433			2,159			4,637			4,347
Depreciation and amortization	1,001			1,079			2,023			2,154
Taxes other than income taxes	411			418			847			863
Total operating expenses	6,769			6,881			14,298			15,142
Gain on sales of assets and businesses	12			33			13			36
Operating income	565			841			1,784			2,060
Other income and (deductions)
Interest expense, net	(421		)	(403		)	(824		)	(800		)
Interest expense to affiliates	(6		)	(6		)	(13		)	(13		)
Other, net	656			212			(68		)	679
Total other income and (deductions)	229			(197		)	(905		)	(134		)
Income before income taxes	794			644			879			1,926
Income taxes	219			144			(75		)	454
Equity in losses of unconsolidated affiliates	(1		)	(6		)	(4		)	(12		)
Net income	574			494			950			1,460
Net income (loss) attributable to noncontrolling interests	53			10			(153		)	69
Net income attributable to common shareholders	$	521		$	484		$	1,103		$	1,391
Comprehensive income, net of income taxes
Net income	$	574		$	494		$	950		$	1,460
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(10		)	(16		)	(20		)	(32		)
Actuarial loss reclassified to periodic benefit cost	47			36			94			74
Pension and non-pension postretirement benefit plan valuation adjustment	2			—			(5		)	(39		)
Unrealized loss on cash flow hedges	—			—			(1		)	—
Unrealized loss on investments in unconsolidated affiliates	—			(2		)	—			(4		)
Unrealized gain (loss) on foreign currency translation	2			3			(6		)	4
Other comprehensive income	41			21			62			3
Comprehensive income	615			515			1,012			1,463
Comprehensive income (loss) attributable to noncontrolling interests	53			9			(153		)	67
Comprehensive income attributable to common shareholders	$	562		$	506		$	1,165		$	1,396
Average shares of common stock outstanding:
Basic	976			972			975			972
Assumed exercise and/or distributions of stock-based awards	—			2			1			1
Diluted(a)	976			974			976			973
Earnings per average common share:
Basic	$	0.53		$	0.50		$	1.13		$	1.43
Diluted	$	0.53		$	0.50		$	1.13		$	1.43

__________

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

See the Combined Notes to Consolidated Financial Statements

10

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
(In millions)	2020			2019
Cash flows from operating activities
Net income	$	950		$	1,460
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	2,741			2,922
Asset impairments	33			9
Gain on sales of assets and businesses	(13		)	(33		)
Deferred income taxes and amortization of investment tax credits	33			284
Net fair value changes related to derivatives	(194		)	107
Net realized and unrealized losses (gains) on NDT funds	196			(404		)
Other non-cash operating activities	671			277
Changes in assets and liabilities:
Accounts receivable	1,318			618
Inventories	(14		)	19
Accounts payable and accrued expenses	(798		)	(924		)
Option premiums (paid) received, net	(102		)	48
Collateral received (posted), net	340			(311		)
Income taxes	(114		)	151
Pension and non-pension postretirement benefit contributions	(558		)	(355		)
Other assets and liabilities	(1,809		)	(970		)
Net cash flows provided by operating activities	2,680			2,898
Cash flows from investing activities
Capital expenditures	(3,773		)	(3,572		)
Proceeds from NDT fund sales	2,488			6,920
Investment in NDT funds	(2,540		)	(6,847		)
Collection of DPP	1,102			—
Proceeds from sales of assets and businesses	—			14
Other investing activities	4			26
Net cash flows used in investing activities	(2,719		)	(3,459		)
Cash flows from financing activities
Changes in short-term borrowings	(751		)	470
Proceeds from short-term borrowings with maturities greater than 90 days	500			—
Repayments on short-term borrowings with maturities greater than 90 days	—			(125		)
Issuance of long-term debt	6,526			850
Retirement of long-term debt	(3,894		)	(574		)
Dividends paid on common stock	(746		)	(704		)
Proceeds from employee stock plans	46			75
Other financing activities	(84		)	(34		)
Net cash flows provided by (used in) financing activities	1,597			(42		)
Increase (decrease) in cash, cash equivalents and restricted cash	1,558			(603		)
Cash, cash equivalents and restricted cash at beginning of period	1,122			1,781
Cash, cash equivalents and restricted cash at end of period	$	2,680		$	1,178
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(105	)	$	(133	)
Increase in DPP	1,754			—
Increase in PPE related to ARO update	—			301

See the Combined Notes to Consolidated Financial Statements

11

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	2,129	$	587
Restricted cash and cash equivalents	373		358
Accounts receivable
Customer accounts receivable	3,075		4,835
Customer allowance for credit losses	(261)		(243)
Customer accounts receivable, net	2,814		4,592
Other accounts receivable	1,549		1,631
Other allowance for credit losses	(61)		(48)
Other accounts receivable, net	1,488		1,583
Mark-to-market derivative assets	573		679
Unamortized energy contract assets	43		47
Inventories, net
Fossil fuel and emission allowances	273		312
Materials and supplies	1,508		1,456
Regulatory assets	1,193		1,170
Other	2,139		1,253
Total current assets	12,533		12,037
Property, plant and equipment (net of accumulated depreciation and amortization of $24,798 and $23,979 as of June 30, 2020 and December 31, 2019, respectively)	81,748		80,233
Deferred debits and other assets
Regulatory assets	8,313		8,335
Nuclear decommissioning trust funds	12,730		13,190
Investments	424		464
Goodwill	6,677		6,677
Mark-to-market derivative assets	466		508
Unamortized energy contract assets	321		336
Other	3,101		3,197
Total deferred debits and other assets	32,032		32,707
Total assets(a)	$	126,313	$	124,977

See the Combined Notes to Consolidated Financial Statements

12

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020			December 31, 2019
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	1,119		$	1,370
Long-term debt due within one year	2,514			4,710
Accounts payable	3,047			3,560
Accrued expenses	1,616			1,981
Payables to affiliates	5			5
Regulatory liabilities	495			406
Mark-to-market derivative liabilities	204			247
Unamortized energy contract liabilities	113			132
Renewable energy credit obligation	478			443
Other	1,474			1,331
Total current liabilities	11,065			14,185
Long-term debt	36,112			31,329
Long-term debt to financing trusts	390			390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	12,720			12,351
Asset retirement obligations	11,059			10,846
Pension obligations	3,659			4,247
Non-pension postretirement benefit obligations	2,121			2,076
Spent nuclear fuel obligation	1,206			1,199
Regulatory liabilities	9,414			9,986
Mark-to-market derivative liabilities	440			393
Unamortized energy contract liabilities	292			338
Other	2,964			3,064
Total deferred credits and other liabilities	43,875			44,500
Total liabilities(a)	91,442			90,404
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 975 shares and 973 shares outstanding at June 30, 2020 and December 31, 2019, respectively)	19,336			19,274
Treasury stock, at cost (2 shares at June 30, 2020 and December 31, 2019)	(123		)	(123		)
Retained earnings	16,622			16,267
Accumulated other comprehensive loss, net	(3,132		)	(3,194		)
Total shareholders’ equity	32,703			32,224
Noncontrolling interests	2,168			2,349
Total equity	34,871			34,573
Total liabilities and shareholders’ equity	$	126,313		$	124,977

__________

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

See the Combined Notes to Consolidated Financial Statements

13

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Six Months Ended June 30, 2020
(In millions, shares in thousands)	Issued Shares		Common Stock			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interests			Total Shareholders' Equity
Balance, December 31, 2019	974,416		$	19,274		$	(123	)	$	16,267		$	(3,194	)	$	2,349		$	34,573
Net income (loss)	—		—			—			582			—			(206		)	376
Long-term incentive plan activity	1,354		(4		)	—			—			—			—			(4		)
Employee stock purchase plan issuances	470		31			—			—			—			—			31
Changes in equity of noncontrolling interests	—		—			—			—			—			(9		)	(9		)
Sale of noncontrolling interests	—		2			—			—			—			—			2
Common stock dividends ($0.38/common share)	—		—			—			(374		)	—			—			(374		)
Other comprehensive income, net of income taxes	—		—			—			—			21			—			21
Balance, March 31, 2020	976,240		$	19,303		$	(123	)	$	16,475		$	(3,173	)	$	2,134		$	34,616
Net income	—		—			—			521			—			53			574
Long-term incentive plan activity	148		17			—			—			—			—			17
Employee stock purchase plan issuances	(51	)	15			—			—			—			—			15
Changes in equity of noncontrolling interests	—		—			—			—			—			(19		)	(19		)
Sale of noncontrolling interests	—		1			—			—			—			—			1
Common stock dividends ($0.38/common share)	—		—			—			(374		)	—			—			(374		)
Other comprehensive income, net of income taxes	—		—			—			—			41			—			41
Balance, June 30, 2020	976,337		$	19,336		$	(123	)	$	16,622		$	(3,132	)	$	2,168		$	34,871

See the Combined Notes to Consolidated Financial Statements

14

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Six Months Ended June 30, 2019
(In millions, shares in thousands)	Issued Shares	Common Stock			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interests			Total Shareholders' Equity
Balance, December 31, 2018	970,020	$	19,116		$	(123	)	$	14,766		$	(2,995	)	$	2,306		$	33,070
Net income	—	—			—			907			—			59			966
Long-term incentive plan activity	2,446	(3		)	—			—			—			—			(3		)
Employee stock purchase plan issuances	320	51			—			—			—			—			51
Changes in equity of noncontrolling interests	—	—			—			—			—			(17		)	(17		)
Sale of noncontrolling interests	—	7			—			—			—			—			7
Common stock dividends ($0.36/common share)	—	—			—			(352		)	—			—			(352		)
Other comprehensive loss, net of income taxes	—	—			—			—			(17		)	(1		)	(18		)
Balance, March 31, 2019	972,786	$	19,171		$	(123	)	$	15,321		$	(3,012	)	$	2,347		$	33,704
Net income	—	—			—			484			—			10			494
Long-term incentive plan activity	320	14			—			—			—			—			14
Employee stock purchase plan issuances	311	24			—			—			—			—			24
Changes in equity of noncontrolling interests	—	—			—			—			—			3			3
Common stock dividends ($0.36/common share)	—	—			—			(353		)	—			—			(353		)
Other comprehensive income, net of income taxes	—	—			—			—			22			(1		)	21
Balance, June 30, 2019	973,417	$	19,209		$	(123	)	$	15,452		$	(2,990	)	$	2,359		$	33,907

See the Combined Notes to Consolidated Financial Statements

15

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2020			2019			2020			2019
Operating revenues
Operating revenues	$	3,609		$	3,958		$	8,012		$	8,937
Operating revenues from affiliates	271			252			601			569
Total operating revenues	3,880			4,210			8,613			9,506
Operating expenses
Purchased power and fuel	1,945			2,289			4,655			5,493
Purchased power and fuel from affiliates	(3		)	3			(9		)	4
Operating and maintenance	1,053			1,117			2,174			2,185
Operating and maintenance from affiliates	136			149			277			299
Depreciation and amortization	300			409			604			814
Taxes other than income taxes	116			129			246			264
Total operating expenses	3,547			4,096			7,947			9,059
Gain on sales of assets and businesses	12			33			12			33
Operating income	345			147			678			480
Other income and (deductions)
Interest expense, net	(78		)	(107		)	(179		)	(209		)
Interest expense to affiliates	(9		)	(9		)	(18		)	(18		)
Other, net	602			171			(168		)	601
Total other income and (deductions)	515			55			(365		)	374
Income before income taxes	860			202			313			854
Income taxes	329			78			(59		)	301
Equity in losses of unconsolidated affiliates	(2		)	(6		)	(4		)	(13		)
Net income	529			118			368			540
Net income (loss) attributable to noncontrolling interests	53			10			(153		)	68
Net income attributable to membership interest	$	476		$	108		$	521		$	472
Comprehensive income, net of income taxes
Net income	$	529		$	118		$	368		$	540
Other comprehensive income (loss), net of income taxes
Unrealized loss on cash flow hedges	—			(1		)	(1		)	—
Unrealized loss on investments in unconsolidated affiliates	—			(2		)	—			(4		)
Unrealized gain (loss) on foreign currency translation	2			2			(6		)	4
Other comprehensive income (loss)	2			(1		)	(7		)	—
Comprehensive income	531			117			361			540
Comprehensive income (loss) attributable to noncontrolling interests	53			9			(153		)	66
Comprehensive income attributable to membership interest	$	478		$	108		$	514		$	474

See the Combined Notes to Consolidated Financial Statements

16

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
(In millions)	2020			2019
Cash flows from operating activities
Net income	$	368		$	540
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	1,320			1,580
Asset impairments	18			9
Gain on sales of assets and businesses	(12		)	(33		)
Deferred income taxes and amortization of investment tax credits	(54		)	151
Net fair value changes related to derivatives	(193		)	114
Net realized and unrealized losses (gains) on NDT funds	196			(404		)
Other non-cash operating activities	136			(50		)
Changes in assets and liabilities:
Accounts receivable	1,443			472
Receivables from and payables to affiliates, net	68			(18		)
Inventories	(34		)	32
Accounts payable and accrued expenses	(666		)	(507		)
Option premiums (paid) received, net	(102		)	48
Collateral posted, net	342			(318		)
Income taxes	26			321
Pension and non-pension postretirement benefit contributions	(243		)	(158		)
Other assets and liabilities	(1,332		)	(351		)
Net cash flows provided by operating activities	1,281			1,428
Cash flows from investing activities
Capital expenditures	(930		)	(890		)
Proceeds from NDT fund sales	2,488			6,920
Investment in NDT funds	(2,540		)	(6,847		)
Collection of DPP	1,102			—
Proceeds from sales of assets and businesses	—			14
Changes in Exelon intercompany money pool	—			(179		)
Other investing activities	6			8
Net cash flows provided by (used in) investing activities	126			(974		)
Cash flows from financing activities
Changes in short-term borrowings	(220		)	—
Proceeds from short-term borrowings with maturities greater than 90 days	500			—
Issuance of long-term debt	2,403			40
Retirement of long-term debt	(2,936		)	(130		)
Changes in Exelon intercompany money pool	—			(100		)
Distributions to member	(937		)	(449		)
Other financing activities	(30		)	(21		)
Net cash flows used in financing activities	(1,220		)	(660		)
Increase (decrease) in cash, cash equivalents and restricted cash	187			(206		)
Cash, cash equivalents and restricted cash at beginning of period	449			903
Cash, cash equivalents and restricted cash at end of period	$	636		$	697
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(108	)	$	(30	)
Increase in DPP	1,754			—
Increase in PPE related to ARO update	—			301

    

See the Combined Notes to Consolidated Financial Statements

17

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	483	$	303
Restricted cash and cash equivalents	153		146
Accounts receivable
Customer accounts receivable	1,117		2,973
Customer allowance for credit losses	(33)		(80)
Customer accounts receivable, net	1,084		2,893
Other accounts receivable	360		619
Other accounts receivable, net	360		619
Mark-to-market derivative assets	570		675
Receivables from affiliates	118		190
Unamortized energy contract assets	44		47
Inventories, net
Fossil fuel and emission allowances	220		236
Materials and supplies	1,075		1,026
Renewable energy credits	399		336
Other	1,343		605
Total current assets	5,849		7,076
Property, plant and equipment (net of accumulated depreciation and amortization of $12,051 and $12,017 as of June 30, 2020 and December 31, 2019, respectively)	23,954		24,193
Deferred debits and other assets
Nuclear decommissioning trust funds	12,730		13,190
Investments	192		235
Goodwill	47		47
Mark-to-market derivative assets	466		508
Prepaid pension asset	1,613		1,438
Unamortized energy contract assets	320		336
Deferred income taxes	11		12
Other	1,821		1,960
Total deferred debits and other assets	17,200		17,726
Total assets(a)	$	47,003	$	48,995

See the Combined Notes to Consolidated Financial Statements

18

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020			December 31, 2019
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	600		$	320
Long-term debt due within one year	785			2,624
Long-term debt to affiliates due within one year	554			558
Accounts payable	1,075			1,692
Accrued expenses	621			786
Payables to affiliates	113			117
Mark-to-market derivative liabilities	173			215
Unamortized energy contract liabilities	9			17
Renewable energy credit obligation	478			443
Other	430			517
Total current liabilities	4,838			7,289
Long-term debt	5,768			4,464
Long-term debt to affiliates	326			328
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	3,701			3,752
Asset retirement obligations	10,819			10,603
Non-pension postretirement benefit obligations	868			878
Spent nuclear fuel obligation	1,206			1,199
Payables to affiliates	2,751			3,103
Mark-to-market derivative liabilities	154			123
Unamortized energy contract liabilities	10			11
Other	1,335			1,415
Total deferred credits and other liabilities	20,844			21,084
Total liabilities(a)	31,776			33,165
Commitments and contingencies
Equity
Member’s equity
Membership interest	9,569			9,566
Undistributed earnings	3,534			3,950
Accumulated other comprehensive loss, net	(39		)	(32		)
Total member’s equity	13,064			13,484
Noncontrolling interests	2,163			2,346
Total equity	15,227			15,830
Total liabilities and equity	$	47,003		$	48,995

__________

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

See the Combined Notes to Consolidated Financial Statements

19

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

	Six Months Ended June 30, 2020
	Member’s Equity
(In millions)	Membership Interest		Undistributed Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interests			Total Equity
Balance, December 31, 2019	$	9,566	$	3,950		$	(32	)	$	2,346		$	15,830
Net income (loss)	—		45			—			(206		)	(161		)
Changes in equity of noncontrolling interests	—		—			—			(11		)	(11		)
Sale of noncontrolling interests	2		—			—			—			2
Distributions to member	—		(468		)	—			—			(468		)
Other comprehensive loss, net of income taxes	—		—			(9		)	—			(9		)
Balance, March 31, 2020	$	9,568	$	3,527		$	(41	)	$	2,129		$	15,183
Net income	—		476			—			53			529
Changes in equity of noncontrolling interests	—		—			—			(19		)	(19		)
Sale of noncontrolling interests	1		—			—			—			1
Distributions to member	—		(469		)	—			—			(469		)
Other comprehensive income, net of income taxes	—		—			2			—			2
Balance, June 30, 2020	$	9,569	$	3,534		$	(39	)	$	2,163		$	15,227

	Six Months Ended June 30, 2019
	Member’s Equity
(In millions)	Membership Interest		Undistributed Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interests			Total Equity
Balance, December 31, 2018	$	9,518	$	3,724		$	(38	)	$	2,304		$	15,508
Net income	—		363			—			59			422
Changes in equity of noncontrolling interests	—		—			—			(17		)	(17		)
Sale of noncontrolling interests	7		—			—			—			7
Distributions to member	—		(225		)	—			—			(225		)
Other comprehensive income, net of income taxes	—		—			2			(1		)	1
Balance, March 31, 2019	$	9,525	$	3,862		$	(36	)	$	2,345		$	15,696
Net income	—		108			—			10			118
Changes in equity of noncontrolling interests	—		—			—			3			3
Distributions to member	—		(224		)	—			—			(224		)
Other comprehensive loss, net of income taxes	—		—			—			(1		)	(1		)
Balance, June 30, 2019	$	9,525	$	3,746		$	(36	)	$	2,357		$	15,592

See the Combined Notes to Consolidated Financial Statements

20

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2020			2019			2020			2019
Operating revenues
Electric operating revenues	$	1,431		$	1,360		$	2,853		$	2,792
Revenues from alternative revenue programs	(25		)	(14		)	(13		)	(42		)
Operating revenues from affiliates	11			5			16			9
Total operating revenues	1,417			1,351			2,856			2,759
Operating expenses
Purchased power	380			316			770			705
Purchased power from affiliate	84			91			181			187
Operating and maintenance	469			245			713			504
Operating and maintenance from affiliate	67			60			140			122
Depreciation and amortization	274			257			547			508
Taxes other than income taxes	71			71			146			148
Total operating expenses	1,345			1,040			2,497			2,174
Gain on sales of assets	—			—			—			3
Operating income	72			311			359			588
Other income and (deductions)
Interest expense, net	(95		)	(86		)	(186		)	(171		)
Interest expense to affiliates	(3		)	(3		)	(6		)	(7		)
Other, net	11			10			22			19
Total other income and (deductions)	(87		)	(79		)	(170		)	(159		)
(Loss) income before income taxes	(15		)	232			189			429
Income taxes	46			46			82			85
Net (loss) income	$	(61	)	$	186		$	107		$	344
Comprehensive (loss) income	$	(61	)	$	186		$	107		$	344

21

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
(In millions)	2020			2019
Cash flows from operating activities
Net income	$	107		$	344
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	547			508
Asset impairments	15			—
Deferred income taxes and amortization of investment tax credits	129			64
Other non-cash operating activities	283			87
Changes in assets and liabilities:
Accounts receivable	(92		)	56
Receivables from and payables to affiliates, net	(6		)	(16		)
Inventories	(7		)	(5		)
Accounts payable and accrued expenses	4			(121		)
Collateral received (posted), net	(3		)	11
Income taxes	(90		)	43
Pension and non-pension postretirement benefit contributions	(144		)	(68		)
Other assets and liabilities	(245		)	(236		)
Net cash flows provided by operating activities	498			667
Cash flows from investing activities
Capital expenditures	(1,029		)	(961		)
Other investing activities	(4		)	17
Net cash flows used in investing activities	(1,033		)	(944		)
Cash flows from financing activities
Changes in short-term borrowings	(130		)	303
Issuance of long-term debt	1,000			400
Retirement of long-term debt	—			(300		)
Dividends paid on common stock	(249		)	(254		)
Contributions from parent	249			124
Other financing activities	(14		)	(10		)
Net cash flows provided by financing activities	856			263
Increase (decrease) in cash, cash equivalents and restricted cash	321			(14		)
Cash, cash equivalents and restricted cash at beginning of period	403			330
Cash, cash equivalents and restricted cash at end of period	$	724		$	316
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	18		$	(77	)

See the Combined Notes to Consolidated Financial Statements

22

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	403	$	90
Restricted cash and cash equivalents	155		150
Accounts receivable
Customer accounts receivable	706		604
Customer allowance for credit losses	(72)		(59)
Customer accounts receivable, net	634		545
Other accounts receivable	361		306
Other allowance for credit losses	(22)		(20)
Other accounts receivable, net	339		286
Receivables from affiliates	23		28
Inventories, net	166		159
Regulatory assets	271		281
Other	59		44
Total current assets	2,050		1,583
Property, plant and equipment (net of accumulated depreciation and amortization of $5,424 and $5,168 as of June 30, 2020 and December 31, 2019, respectively)	23,717		23,107
Deferred debits and other assets
Regulatory assets	1,610		1,480
Investments	6		6
Goodwill	2,625		2,625
Receivables from affiliates	2,374		2,622
Prepaid pension asset	1,079		995
Other	435		347
Total deferred debits and other assets	8,129		8,075
Total assets	$	33,896	$	32,765

See the Combined Notes to Consolidated Financial Statements

23

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020			December 31, 2019
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	—		$	130
Long-term debt due within one year	500			500
Accounts payable	579			527
Accrued expenses	330			385
Payables to affiliates	92			103
Customer deposits	116			118
Regulatory liabilities	175			200
Mark-to-market derivative liabilities	31			32
Deferred Prosecution Agreement payments	200			—
Other	122			122
Total current liabilities	2,145			2,117
Long-term debt	8,980			7,991
Long-term debt to financing trust	205			205
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	4,201			4,021
Asset retirement obligations	127			128
Non-pension postretirement benefits obligations	177			180
Regulatory liabilities	6,309			6,542
Mark-to-market derivative liabilities	287			269
Other	681			635
Total deferred credits and other liabilities	11,782			11,775
Total liabilities	23,112			22,088
Commitments and contingencies
Shareholders’ equity
Common stock	1,588			1,588
Other paid-in capital	7,821			7,572
Retained deficit unappropriated	(1,700		)	(1,639		)
Retained earnings appropriated	3,075			3,156
Total shareholders’ equity	10,784			10,677
Total liabilities and shareholders’ equity	$	33,896		$	32,765

See the Combined Notes to Consolidated Financial Statements

24

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Six Months Ended June 30, 2020
(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated			Retained Earnings Appropriated			Total Shareholders’ Equity
Balance, December 31, 2019	$	1,588	$	7,572	$	(1,639	)	$	3,156		$	10,677
Net income	—		—		168			—			168
Appropriation of retained earnings for future dividends	—		—		(168		)	168			—
Common stock dividends	—		—		—			(125		)	(125		)
Contributions from parent	—		125		—			—			125
Balance, March 31, 2020	$	1,588	$	7,697	$	(1,639	)	$	3,199		$	10,845
Net loss	—		—		(61		)	—			(61		)
Common stock dividends	—		—		—			(124		)	(124		)
Contributions from parent	—		124		—			—			124
Balance, June 30, 2020	$	1,588	$	7,821	$	(1,700	)	$	3,075		$	10,784
	Six Months Ended June 30, 2019
(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated			Retained Earnings Appropriated			Total Shareholders’ Equity
Balance, December 31, 2018	$	1,588	$	7,322	$	(1,639	)	$	2,976		$	10,247
Net income	—		—		157			—			157
Appropriation of retained earnings for future dividends	—		—		(157		)	157			—
Common stock dividends	—		—		—			(127		)	(127		)
Contributions from parent	—		63		—			—			63
Balance, March 31, 2019	$	1,588	$	7,385	$	(1,639	)	$	3,006		$	10,340
Net income	—		—		186			—			186
Appropriation of retained earnings for future dividends	—		—		(186		)	186			—
Common stock dividends	—		—		—			(127		)	(127		)
Contributions from parent	—		61		—			—			61
Balance, June 30, 2019	$	1,588	$	7,446	$	(1,639	)	$	3,065		$	10,460

See the Combined Notes to Consolidated Financial Statements

25

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2020			2019			2020			2019
Operating revenues
Electric operating revenues	$	580		$	567		$	1,180		$	1,188
Natural gas operating revenues	95			89			304			369
Revenues from alternative revenue programs	4			(3		)	5			(6		)
Operating revenues from affiliates	2			2			4			3
Total operating revenues	681			655			1,493			1,554
Operating expenses
Purchased power	142			124			306			275
Purchased fuel	34			32			117			166
Purchased power from affiliate	40			35			76			79
Operating and maintenance	235			162			414			349
Operating and maintenance from affiliates	40			37			78			75
Depreciation and amortization	88			83			173			164
Taxes other than income taxes	39			37			78			79
Total operating expenses	618			510			1,242			1,187
Operating income	63			145			251			367
Other income and (deductions)
Interest expense, net	(33		)	(30		)	(65		)	(61		)
Interest expense to affiliates	(3		)	(3		)	(6		)	(6		)
Other, net	5			3			7			7
Total other income and (deductions)	(31		)	(30		)	(64		)	(60		)
Income before income taxes	32			115			187			307
Income taxes	(7		)	13			9			37
Net income	$	39		$	102		$	178		$	270
Comprehensive income	$	39		$	102		$	178		$	270

See the Combined Notes to Consolidated Financial Statements

26

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
(In millions)	2020			2019
Cash flows from operating activities
Net income	$	178		$	270
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	173			164
Deferred income taxes and amortization of investment tax credits	6			8
Other non-cash operating activities	25			15
Changes in assets and liabilities:
Accounts receivable	22			39
Receivables from and payables to affiliates, net	3			(4		)
Inventories	10			12
Accounts payable and accrued expenses	27			(31		)
Income taxes	15			(11		)
Pension and non-pension postretirement benefit contributions	(18		)	(27		)
Other assets and liabilities	(48		)	(117		)
Net cash flows provided by operating activities	393			318
Cash flows from investing activities
Capital expenditures	(512		)	(447		)
Changes in Exelon intercompany money pool	68			—
Other investing activities	3			4
Net cash flows used in investing activities	(441		)	(443		)
Cash flows from financing activities
Issuance of long-term debt	350			—
Changes in Exelon intercompany money pool	—			52
Dividends paid on common stock	(170		)	(180		)
Contributions from parent	231			145
Other financing activities	(3		)	(1		)
Net cash flows provided by financing activities	408			16
Increase (decrease) in cash, cash equivalents and restricted cash	360			(109		)
Cash, cash equivalents and restricted cash at beginning of period	27			135
Cash, cash equivalents and restricted cash at end of period	$	387		$	26
Supplemental cash flow information
Increase in capital expenditures not paid	$	42		$	33

See the Combined Notes to Consolidated Financial Statements

27

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	380	$	21
Restricted cash and cash equivalents	7		6
Accounts receivable
Customer accounts receivable	379		412
Customer allowance for credit losses	(71)		(55)
Customer accounts receivable, net	308		357
Other accounts receivable	128		145
Other allowance for credit losses	(7)		(7)
Other accounts receivable, net	121		138
Receivables from affiliates	—		1
Receivable from Exelon intercompany money pool	—		68
Inventories, net
Fossil fuel	26		36
Materials and supplies	35		35
Prepaid utility taxes	76		—
Regulatory assets	46		41
Other	21		19
Total current assets	1,020		722
Property, plant and equipment (net of accumulated depreciation and amortization of $3,782 and $3,718 as of June 30, 2020 and December 31, 2019, respectively)	9,688		9,292
Deferred debits and other assets
Regulatory assets	604		554
Investments	27		27
Receivables from affiliates	376		480
Prepaid pension asset	379		365
Other	26		29
Total deferred debits and other assets	1,412		1,455
Total assets	$	12,120	$	11,469

See the Combined Notes to Consolidated Financial Statements

28

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Accounts payable	$	463	$	387
Accrued expenses	92		101
Payables to affiliates	57		55
Customer deposits	67		69
Regulatory liabilities	116		91
Other	29		19
Total current liabilities	824		722
Long-term debt	3,752		3,405
Long-term debt to financing trusts	184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,139		2,080
Asset retirement obligations	26		28
Non-pension postretirement benefits obligations	287		288
Regulatory liabilities	404		510
Other	86		74
Total deferred credits and other liabilities	2,942		2,980
Total liabilities	7,702		7,291
Commitments and contingencies
Shareholder’s equity
Common stock	2,997		2,766
Retained earnings	1,421		1,412
Total shareholder’s equity	4,418		4,178
Total liabilities and shareholder's equity	$	12,120	$	11,469

See the Combined Notes to Consolidated Financial Statements

29

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)

	Six months ended June 30, 2020
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2019	$	2,766	$	1,412		$	4,178
Net income	—		140			140
Common stock dividends	—		(85		)	(85		)
Contributions from parent	231		—			231
Balance, March 31, 2020	$	2,997	$	1,467		$	4,464
Net income	—		39			39
Common stock dividends	—		(85		)	(85		)
Balance, June 30, 2020	$	2,997	$	1,421		$	4,418
	Six months ended June 30, 2019
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2018	$	2,578	$	1,242		$	3,820
Net income	—		168			168
Common stock dividends	—		(90		)	(90		)
Contributions from parent	145		—			145
Balance, March 31, 2019	$	2,723	$	1,320		$	4,043
Net income	—		102			102
Common stock dividends	—		(90		)	(90		)
Balance, June 30, 2019	$	2,723	$	1,332		$	4,055

See the Combined Notes to Consolidated Financial Statements

30

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2020			2019			2020			2019
Operating revenues
Electric operating revenues	$	530		$	540		$	1,125		$	1,191
Natural gas operating revenues	119			97			419			405
Revenues from alternative revenue programs	(37		)	6			—			17
Operating revenues from affiliates	4			6			10			12
Total operating revenues	616			649			1,554			1,625
Operating expenses
Purchased power	107			131			221			322
Purchased fuel	18			21			95			116
Purchased power and fuel from affiliate	69			56			167			132
Operating and maintenance	146			142			293			294
Operating and maintenance from affiliates	41			40			83			78
Depreciation and amortization	129			117			272			252
Taxes other than income taxes	63			62			132			131
Total operating expenses	573			569			1,263			1,325
Operating income	43			80			291			300
Other income and (deductions)
Interest expense, net	(32		)	(29		)	(64		)	(58		)
Other, net	6			5			10			11
Total other income and (deductions)	(26		)	(24		)	(54		)	(47		)
Income before income taxes	17			56			237			253
Income taxes	(22		)	11			18			47
Net income	$	39		$	45		$	219		$	206
Comprehensive income	$	39		$	45		$	219		$	206

See the Combined Notes to Consolidated Financial Statements

31

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
(In millions)	2020			2019
Cash flows from operating activities
Net income	$	219		$	206
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	272			252
Deferred income taxes and amortization of investment tax credits	22			47
Other non-cash operating activities	50			41
Changes in assets and liabilities:
Accounts receivable	19			85
Receivables from and payables to affiliates, net	(26		)	(14		)
Inventories	10			5
Accounts payable and accrued expenses	(15		)	(73		)
Collateral posted, net	—			(5		)
Income taxes	26			(29		)
Pension and non-pension postretirement benefit contributions	(68		)	(42		)
Other assets and liabilities	(5		)	(21		)
Net cash flows provided by operating activities	504			452
Cash flows from investing activities
Capital expenditures	(548		)	(542		)
Other investing activities	(4		)	4
Net cash flows used in investing activities	(552		)	(538		)
Cash flows from financing activities
Changes in short-term borrowings	(76		)	194
Issuance of long-term debt	400			—
Dividends paid on common stock	(123		)	(112		)
Contributions from parent	26			—
Other financing activities	(8		)	—
Net cash flows provided by financing activities	219			82
Increase (decrease) in cash, cash equivalents and restricted cash	171			(4		)
Cash, cash equivalents and restricted cash at beginning of period	25			13
Cash, cash equivalents and restricted cash at end of period	$	196		$	9
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(14	)	$	24

See the Combined Notes to Consolidated Financial Statements

32

BALTIMORE GAS AND ELECTRIC COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	195	$	24
Restricted cash and cash equivalents	1		1
Accounts receivable
Customer accounts receivable	318		329
Customer allowance for credit losses	(23)		(12)
Customer accounts receivable, net	295		317
Other accounts receivable	121		152
Other allowance for credit losses	(6)		(5)
Other accounts receivable, net	115		147
Receivables from affiliates	—		1
Inventories, net
Fossil fuel	22		30
Materials and supplies	44		46
Prepaid utility taxes	—		78
Regulatory assets	177		183
Other	6		6
Total current assets	855		833
Property, plant and equipment (net of accumulated depreciation and amortization of $3,906 and $3,834 as of June 30, 2020 and December 31, 2019, respectively)	9,332		8,990
Deferred debits and other assets
Regulatory assets	464		454
Investments	10		7
Prepaid pension asset	295		264
Other	71		86
Total deferred debits and other assets	840		811
Total assets	$	11,027	$	10,634

See the Combined Notes to Consolidated Financial Statements

33

BALTIMORE GAS AND ELECTRIC COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	76
Accounts payable	244		243
Accrued expenses	120		152
Payables to affiliates	41		66
Customer deposits	118		120
Regulatory liabilities	44		33
Other	63		63
Total current liabilities	630		753
Long-term debt	3,663		3,270
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,480		1,396
Asset retirement obligations	22		22
Non-pension postretirement benefits obligations	193		199
Regulatory liabilities	1,131		1,195
Other	103		116
Total deferred credits and other liabilities	2,929		2,928
Total liabilities	7,222		6,951
Commitments and contingencies
Shareholder's equity
Common stock	1,933		1,907
Retained earnings	1,872		1,776
Total shareholder's equity	3,805		3,683
Total liabilities and shareholder's equity	$	11,027	$	10,634

See the Combined Notes to Consolidated Financial Statements

34

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

	Six Months Ended June 30, 2020
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2019	$	1,907	$	1,776		$	3,683
Net income	—		181			181
Common stock dividends	—		(62		)	(62		)
Balance, March 31, 2020	$	1,907	$	1,895		$	3,802
Net income	—		39			39
Common stock dividends	—		(62		)	(62		)
Contributions from parent	26		—			26
Balance, June 30, 2020	$	1,933	$	1,872		$	3,805
	Six Months Ended June 30, 2019
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2018	$	1,714	$	1,640		$	3,354
Net income	—		160			160
Common stock dividends	—		(56		)	(56		)
Balance, March 31, 2019	$	1,714	$	1,744		$	3,458
Net income	—		45			45
Common stock dividends	—		(55		)	(55		)
Balance, June 30, 2019	$	1,714	$	1,734		$	3,448

See the Combined Notes to Consolidated Financial Statements

35

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2020			2019			2020			2019
Operating revenues
Electric operating revenues	$	1,047		$	1,067		$	2,133		$	2,205
Natural gas operating revenues	30			24			94			95
Revenues from alternative revenue programs	(64		)	(3		)	(47		)	12
Operating revenues from affiliates	3			3			7			7
Total operating revenues	1,016			1,091			2,187			2,319
Operating expenses
Purchased power	286			303			586			658
Purchased fuel	11			9			42			43
Purchased power from affiliates	78			70			182			171
Operating and maintenance	245			213			464			452
Operating and maintenance from affiliates	36			35			74			68
Depreciation and amortization	191			188			385			369
Taxes other than income taxes	109			108			222			220
Total operating expenses	956			926			1,955			1,981
Gain on sales of assets	—			—			2			—
Operating income	60			165			234			338
Other income and (deductions)
Interest expense, net	(67		)	(67		)	(134		)	(131		)
Other, net	14			14			26			27
Total other income and (deductions)	(53		)	(53		)	(108		)	(104		)
Income before income taxes	7			112			126			234
Income taxes	(87		)	6			(76		)	11
Net income	$	94		$	106		$	202		$	223
Comprehensive income	$	94		$	106		$	202		$	223

See the Combined Notes to Consolidated Financial Statements

36

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
(In millions)	2020			2019
Cash flows from operating activities
Net income	$	202		$	223
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	385			369
Deferred income taxes and amortization of investment tax credits	(74		)	2
Other non-cash operating activities	107			54
Changes in assets and liabilities:
Accounts receivable	(64		)	(34		)
Receivables from and payables to affiliates, net	(22		)	(8		)
Inventories	6			(25		)
Accounts payable and accrued expenses	14			(25		)
Income taxes	(30		)	(12		)
Pension and non-pension postretirement benefit contributions	(31		)	(11		)
Other assets and liabilities	(146		)	(114		)
Net cash flows provided by operating activities	347			419
Cash flows from investing activities
Capital expenditures	(686		)	(698		)
Other investing activities	2			2
Net cash flows used in investing activities	(684		)	(696		)
Cash flows from financing activities
Changes in short-term borrowings	(189		)	(27		)
Repayments of short-term borrowings with maturities greater than 90 days	—			(125		)
Issuance of long-term debt	373			410
Retirement of long-term debt	(35		)	(125		)
Changes in Exelon intercompany money pool	10			3
Distributions to member	(268		)	(216		)
Contributions from member	359			283
Other financing activities	(8		)	(4		)
Net cash flows provided by financing activities	242			199
Decrease in cash, cash equivalents and restricted cash	(95		)	(78		)
Cash, cash equivalents and restricted cash at beginning of period	181			186
Cash, cash equivalents and restricted cash at end of period	$	86		$	108
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(24	)	$	(74	)

See the Combined Notes to Consolidated Financial Statements

37

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	39	$	131
Restricted cash and cash equivalents	36		36
Accounts receivable
Customer accounts receivable	554		516
Customer allowance for credit losses	(62)		(37)
Customer accounts receivable, net	492		479
Other accounts receivable	234		190
Other allowance for credit losses	(26)		(16)
Other accounts receivable, net	208		174
Receivables from affiliates	1		1
Inventories, net
Fossil fuel	5		8
Materials and supplies	187		190
Regulatory assets	449		412
Other	75		49
Total current assets	1,492		1,480
Property, plant and equipment (net of accumulated depreciation and amortization of $1,591 and $1,213 as of June 30, 2020 and December 31, 2019, respectively)	14,692		14,296
Deferred debits and other assets
Regulatory assets	1,962		2,061
Investments	135		135
Goodwill	4,005		4,005
Prepaid pension asset	396		406
Deferred income taxes	13		13
Other	309		323
Total deferred debits and other assets	6,820		6,943
Total assets(a)	$	23,004	$	22,719

See the Combined Notes to Consolidated Financial Statements

38

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020			December 31, 2019
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings	$	19		$	208
Long-term debt due within one year	350			103
Accounts payable	486			462
Accrued expenses	238			296
Payables to affiliates	76			98
Borrowings from Exelon intercompany money pool	22			12
Customer deposits	115			117
Regulatory liabilities	148			70
Unamortized energy contract liabilities	103			115
Other	128			131
Total current liabilities	1,685			1,612
Long-term debt	6,540			6,460
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,350			2,278
Asset retirement obligations	57			57
Non-pension postretirement benefit obligations	87			93
Regulatory liabilities	1,553			1,707
Unamortized energy contract liabilities	282			327
Other	549			577
Total deferred credits and other liabilities	4,878			5,039
Total liabilities(a)	13,103			13,111
Commitments and contingencies
Member's equity
Membership interest	9,977			9,618
Undistributed losses	(76		)	(10		)
Total member's equity	9,901			9,608
Total liabilities and member's equity	$	23,004		$	22,719

__________

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

See the Combined Notes to Consolidated Financial Statements

39

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

	Six Months Ended June 30, 2020
(In millions)	Membership Interest		Undistributed Earnings (Losses)			Member's Equity
Balance, December 31, 2019	$	9,618	$	(10	)	$	9,608
Net income	—		108			108
Distributions to member	—		(134		)	(134		)
Contributions from member	144		—			144
Balance, March 31, 2020	$	9,762	$	(36	)	$	9,726
Net income	—		94			94
Distributions to member	—		(134		)	(134		)
Contributions from member	215		—			215
Balance, June 30, 2020	$	9,977	$	(76	)	$	9,901

	Six Months Ended June 30, 2019
(In millions)	Membership Interest		Undistributed Earnings (Losses)			Member's Equity
Balance, December 31, 2018	$	9,220	$	62		$	9,282
Net income	—		117			117
Distributions to member	—		(128		)	(128		)
Contributions from member	19		—			19
Balance, March 31, 2019	$	9,239	$	51		$	9,290
Net income	—		106			106
Distributions to member	—		(88		)	(88		)
Contributions from member	264		—			264
Balance, June 30, 2019	$	9,503	$	69		$	9,572

See the Combined Notes to Consolidated Financial Statements

40

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2020			2019			2020			2019
Operating revenues
Electric operating revenues	$	506		$	531		$	1,034		$	1,090
Revenues from alternative revenue programs	(13		)	(1		)	2			13
Operating revenues from affiliates	1			1			3			3
Total operating revenues	494			531			1,039			1,106
Operating expenses
Purchased power	78			92			164			209
Purchased power from affiliate	60			52			139			122
Operating and maintenance	67			59			128			123
Operating and maintenance from affiliates	52			52			103			107
Depreciation and amortization	92			93			186			186
Taxes other than income taxes	87			90			179			182
Total operating expenses	436			438			899			929
Operating income	58			93			140			177
Other income and (deductions)
Interest expense, net	(34		)	(34		)	(68		)	(68		)
Other, net	9			7			18			14
Total other income and (deductions)	(25		)	(27		)	(50		)	(54		)
Income before income taxes	33			66			90			123
Income taxes	(24		)	2			(19		)	4
Net income	$	57		$	64		$	109		$	119
Comprehensive income	$	57		$	64		$	109		$	119

See the Combined Notes to Consolidated Financial Statements

41

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
(In millions)	2020			2019
Cash flows from operating activities
Net income	$	109		$	119
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	186			186
Deferred income taxes and amortization of investment tax credits	(22		)	10
Other non-cash operating activities	11			8
Changes in assets and liabilities:
Accounts receivable	(45		)	(36		)
Receivables from and payables to affiliates, net	(22		)	4
Inventories	3			(20		)
Accounts payable and accrued expenses	11			(25		)
Income taxes	(18		)	(23		)
Pension and non-pension postretirement benefit contributions	(6		)	(6		)
Other assets and liabilities	(52		)	(40		)
Net cash flows provided by operating activities	155			177
Cash flows from investing activities
Capital expenditures	(324		)	(298		)
Changes in PHI intercompany money pool	—			(38		)
Other investing activities	(3		)	1
Net cash flows used in investing activities	(327		)	(335		)
Cash flows from financing activities
Changes in short-term borrowings	(68		)	(40		)
Issuance of long-term debt	150			260
Retirement of long-term debt	(1		)	(117		)
Changes in PHI intercompany money pool	50			—
Dividends paid on common stock	(101		)	(72		)
Contributions from parent	137			129
Other financing activities	(6		)	(3		)
Net cash flows provided by financing activities	161			157
Decrease in cash, cash equivalents and restricted cash	(11		)	(1		)
Cash, cash equivalents and restricted cash at beginning of period	63			53
Cash, cash equivalents and restricted cash at end of period	$	52		$	52
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(28	)	$	(18	)

See the Combined Notes to Consolidated Financial Statements

42

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	19	$	30
Restricted cash and cash equivalents	33		33
Accounts receivable
Customer accounts receivable	272		244
Customer allowance for credit losses	(24)		(13)
Customer accounts receivable, net	248		231
Other accounts receivable	121		98
Other allowance for credit losses	(11)		(7)
Other accounts receivable, net	110		91
Receivables from affiliates	2		—
Inventories, net	109		112
Regulatory assets	215		188
Other	11		11
Total current assets	747		696
Property, plant and equipment (net of accumulated depreciation and amortization of $3,604 and $3,517 as of June 30, 2020 and December 31, 2019, respectively)	7,102		6,909
Deferred debits and other assets
Regulatory assets	556		584
Investments	111		110
Prepaid pension asset	290		296
Other	63		66
Total deferred debits and other assets	1,020		1,056
Total assets	$	8,869	$	8,661

See the Combined Notes to Consolidated Financial Statements

43

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	14	$	82
Long-term debt due within one year	3		2
Accounts payable	195		195
Accrued expenses	123		156
Payables to affiliates	46		66
Borrowings from PHI intercompany money pool	50		—
Customer deposits	57		57
Regulatory liabilities	48		8
Merger related obligation	39		39
Current portion of DC PLUG obligation	30		30
Other	16		22
Total current liabilities	621		657
Long-term debt	3,010		2,862
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,168		1,131
Asset retirement obligations	41		41
Non-pension postretirement benefit obligations	15		20
Regulatory liabilities	686		746
Other	276		297
Total deferred credits and other liabilities	2,186		2,235
Total liabilities	5,817		5,754
Commitments and contingencies
Shareholder's equity
Common stock	1,933		1,796
Retained earnings	1,119		1,111
Total shareholder's equity	3,052		2,907
Total liabilities and shareholder's equity	$	8,869	$	8,661

See the Combined Notes to Consolidated Financial Statements

44

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

	Six Months Ended June 30, 2020
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2019	$	1,796	$	1,111		$	2,907
Net income	—		52			52
Common stock dividends	—		(28		)	(28		)
Contributions from parent	137		—			137
Balance, March 31, 2020	$	1,933	$	1,135		$	3,068
Net income	—		57			57
Common stock dividends	—		(73		)	(73		)
Balance, June 30, 2020	$	1,933	$	1,119		$	3,052

	Six Months Ended June 30, 2019
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2018	$	1,636	$	1,104		$	2,740
Net income	—		55			55
Common stock dividends	—		(24		)	(24		)
Contributions from parent	14		—			14
Balance, March 31, 2019	$	1,650	$	1,135		$	2,785
Net income	—		64			64
Common stock dividends	—		(48		)	(48		)
Contributions from parent	115		—			115
Balance, June 30, 2019	$	1,765	$	1,151		$	2,916

See the Combined Notes to Consolidated Financial Statements

45

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2020			2019			2020			2019
Operating revenues
Electric operating revenues	$	260		$	261		$	543		$	568
Natural gas operating revenues	30			24			94			95
Revenues from alternative revenue programs	(25		)	—			(24		)	1
Operating revenues from affiliates	2			2			4			3
Total operating revenues	267			287			617			667
Operating expenses
Purchased power	80			86			169			193
Purchased fuel	11			9			42			43
Purchased power from affiliates	16			12			38			35
Operating and maintenance	54			39			97			84
Operating and maintenance from affiliates	38			38			75			76
Depreciation and amortization	47			45			94			91
Taxes other than income taxes	17			14			32			28
Total operating expenses	263			243			547			550
Operating income	4			44			70			117
Other income and (deductions)
Interest expense, net	(15		)	(15		)	(31		)	(30		)
Other, net	2			5			5			7
Total other income and (deductions)	(13		)	(10		)	(26		)	(23		)
(Loss) income before income taxes	(9		)	34			44			94
Income taxes	(28		)	4			(20		)	11
Net income	$	19		$	30		$	64		$	83
Comprehensive income	$	19		$	30		$	64		$	83

See the Combined Notes to Consolidated Financial Statements

46

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
(In millions)	2020			2019
Cash flows from operating activities
Net income	$	64		$	83
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	94			91
Deferred income taxes and amortization of investment tax credits	(19		)	(5		)
Other non-cash operating activities	40			11
Changes in assets and liabilities:
Accounts receivable	6			15
Receivables from and payables to affiliates, net	(2		)	(11		)
Inventories	—			(3		)
Accounts payable and accrued expenses	3			6
Income taxes	(12		)	11
Pension and non-pension postretirement benefit contributions	—			(1		)
Other assets and liabilities	(21		)	(26		)
Net cash flows provided by operating activities	153			171
Cash flows from investing activities
Capital expenditures	(184		)	(160		)
Changes in PHI intercompany money pool	(55		)	—
Other investing activities	(3		)	1
Net cash flows used in investing activities	(242		)	(159		)
Cash flows from financing activities
Changes in short-term borrowings	(56		)	—
Issuance of long-term debt	100			—
Retirement of long-term debt	(1		)	—
Changes in PHI intercompany money pool	—			38
Dividends paid on common stock	(66		)	(70		)
Contributions from parent	106			—
Other financing activities	(1		)	—
Net cash flows provided by (used in) financing activities	82			(32		)
Decrease in cash, cash equivalents and restricted cash	(7		)	(20		)
Cash, cash equivalents and restricted cash at beginning of period	13			24
Cash, cash equivalents and restricted cash at end of period	$	6		$	4
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(4	)	$	(17	)

See the Combined Notes to Consolidated Financial Statements

47

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	6	$	13
Accounts receivable
Customer accounts receivable	145		152
Customer allowance for credit losses	(18)		(11)
Customer accounts receivable, net	127		141
Other accounts receivable	48		42
Other allowance for credit losses	(7)		(4)
Other accounts receivable, net	41		38
Receivables from affiliates	1		—
Receivable from PHI intercompany pool	55		—
Inventories, net
Fossil fuel	5		8
Materials and supplies	47		44
Prepaid utility taxes	2		18
Regulatory assets	55		52
Renewable energy credits	21		9
Other	3		2
Total current assets	363		325
Property, plant and equipment (net of accumulated depreciation and amortization of $1,476 and $1,425 as of June 30, 2020 and December 31, 2019, respectively)	4,143		4,035
Deferred debits and other assets
Regulatory assets	222		222
Goodwill	8		8
Prepaid pension asset	166		171
Other	64		69
Total deferred debits and other assets	460		470
Total assets	$	4,966	$	4,830

See the Combined Notes to Consolidated Financial Statements

48

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	56
Long-term debt due within one year	81		80
Accounts payable	113		112
Accrued expenses	34		46
Payables to affiliates	27		32
Customer deposits	35		36
Regulatory liabilities	60		37
Other	17		15
Total current liabilities	367		414
Long-term debt	1,594		1,487
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	680		655
Non-pension postretirement benefits obligations	15		16
Regulatory liabilities	526		574
Other	100		104
Total deferred credits and other liabilities	1,321		1,349
Total liabilities	3,282		3,250
Commitments and contingencies
Shareholder's equity
Common stock	1,083		977
Retained earnings	601		603
Total shareholder's equity	1,684		1,580
Total liabilities and shareholder's equity	$	4,966	$	4,830

See the Combined Notes to Consolidated Financial Statements

49

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

	Six Months Ended June 30, 2020
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2019	$	977	$	603		$	1,580
Net income	—		45			45
Common stock dividends	—		(52		)	(52		)
Contributions from parent	6		—			6
Balance, March 31, 2020	983		596			1,579
Net income	—		19			19
Common stock dividends	—		(14		)	(14		)
Contributions from parent	100		—			100
Balance, June 30, 2020	$	1,083	$	601		$	1,684

	Six Months Ended June 30, 2019
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2018	$	914	$	595		$	1,509
Net income	—		53			53
Common stock dividends	—		(41		)	(41		)
Balance, March 31, 2019	914		607			1,521
Net income	—		30			30
Common stock dividends	—		(29		)	(29		)
Balance, June 30, 2019	$	914	$	608		$	1,522

See the Combined Notes to Consolidated Financial Statements

50

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2020			2019			2020			2019
Operating revenues
Electric operating revenues	$	281		$	275		$	556		$	547
Revenues from alternative revenue programs	(26		)	(2		)	(25		)	(1		)
Operating revenues from affiliates	1			1			1			1
Total operating revenues	256			274			532			547
Operating expenses
Purchased power	128			125			254			257
Purchased power from affiliate	2			6			5			13
Operating and maintenance	48			41			94			88
Operating and maintenance from affiliates	34			33			66			67
Depreciation and amortization	44			40			86			71
Taxes other than income taxes	2			1			4			2
Total operating expenses	258			246			509			498
Gain on sale of assets	—			—			2			—
Operating (loss) income	(2		)	28			25			49
Other income and (deductions)
Interest expense, net	(15		)	(15		)	(29		)	(28		)
Other, net	2			1			3			4
Total other income and (deductions)	(13		)	(14		)	(26		)	(24		)
(Loss) income before income taxes	(15		)	14			(1		)	25
Income taxes	(33		)	—			(32		)	1
Net income	$	18		$	14		$	31		$	24
Comprehensive income	$	18		$	14		$	31		$	24

See the Combined Notes to Consolidated Financial Statements

51

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
(In millions)	2020			2019
Cash flows from operating activities
Net income	$	31		$	24
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	86			71
Deferred income taxes and amortization of investment tax credits	(30		)	2
Other non-cash operating activities	34			7
Changes in assets and liabilities:
Accounts receivable	(23		)	(11		)
Receivables from and payables to affiliates, net	9			(9		)
Inventories	2			(1		)
Accounts payable and accrued expenses	17			16
Income taxes	2			6
Pension and non-pension postretirement benefit contributions	(2		)	—
Other assets and liabilities	(68		)	(44		)
Net cash flows provided by operating activities	58			61
Cash flows from investing activities
Capital expenditures	(178		)	(227		)
Other investing activities	5			—
Net cash flows used in investing activities	(173		)	(227		)
Cash flows from financing activities
Changes in short-term borrowings	(65		)	13
Repayments of short-term borrowings with maturities greater than 90 days	—			(125		)
Issuance of long-term debt	123			150
Retirement of long-term debt	(34		)	(9		)
Changes in PHI intercompany money pool	5			—
Dividends paid on common stock	(35		)	(24		)
Contributions from parent	116			155
Other financing activities	(1		)	(1		)
Net cash flows provided by financing activities	109			159
Decrease in cash, cash equivalents and restricted cash	(6		)	(7		)
Cash, cash equivalents and restricted cash at beginning of period	28			30
Cash, cash equivalents and restricted cash at end of period	$	22		$	23
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	7		$	(35	)

See the Combined Notes to Consolidated Financial Statements

52

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
ASSETS
Current assets
Cash and cash equivalents	$	8	$	12
Restricted cash and cash equivalents	3		2
Accounts receivable
Customer accounts receivable	137		121
Customer allowance for credit losses	(20)		(13)
Customer accounts receivable, net	117		108
Other accounts receivable	59		53
Other allowance for credit losses	(8)		(5)
Other accounts receivable, net	51		48
Receivables from affiliates	1		4
Inventories, net	32		34
Prepaid utility taxes	34		—
Regulatory assets	71		57
Other	4		5
Total current assets	321		270
Property, plant and equipment (net of accumulated depreciation and amortization of $1,261 and $1,210 as of June 30, 2020 and December 31, 2019, respectively)	3,302		3,190
Deferred debits and other assets
Regulatory assets	369		368
Prepaid pension asset	47		52
Other	50		53
Total deferred debits and other assets	466		473
Total assets(a)	$	4,089	$	3,933

See the Combined Notes to Consolidated Financial Statements

53

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	June 30, 2020		December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	5	$	70
Long-term debt due within one year	260		20
Accounts payable	170		144
Accrued expenses	39		42
Payables to affiliates	31		25
Borrowings from PHI intercompany money pool	5		—
Customer deposits	24		25
Regulatory liabilities	40		25
Other	8		9
Total current liabilities	582		360
Long-term debt	1,160		1,307
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	590		577
Non-pension postretirement benefit obligations	17		17
Regulatory liabilities	312		357
Other	40		39
Total deferred credits and other liabilities	959		990
Total liabilities(a)	2,701		2,657
Commitments and contingencies
Shareholder's equity
Common stock	1,270		1,154
Retained earnings	118		122
Total shareholder's equity	1,388		1,276
Total liabilities and shareholder's equity	$	4,089	$	3,933

__________

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

See the Combined Notes to Consolidated Financial Statements

54

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

	Six Months Ended June 30, 2020
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2019	$	1,154	$	122		$	1,276
Net income	—		13			13
Common stock dividends	—		(23		)	(23		)
Contributions from parent	1		—			1
Balance, March 31, 2020	1,155		112			1,267
Net income	—		18			18
Common stock dividends	—		(12		)	(12		)
Contributions from parent	115		—			115
Balance, June 30, 2020	$	1,270	$	118		$	1,388

	Six Months Ended June 30, 2019
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2018	$	979	$	147		$	1,126
Net income	—		10			10
Common stock dividends	—		(12		)	(12		)
Contributions from parent	5		—			5
Balance, March 31, 2019	984		145			1,129
Net income	—		14			14
Common stock dividends	—		(12		)	(12		)
Contributions from parent	150		—			150
Balance, June 30, 2019	$	1,134	$	147		$	1,281

See the Combined Notes to Consolidated Financial Statements

55

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 — Significant Accounting Policies

1. Significant Accounting Policies (All Registrants)

Description of Business (All Registrants)

Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.

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

Basis of Presentation (All Registrants)

Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

The accompanying consolidated financial statements as of June 30, 2020 and December 31, 2019 and for the three and six months ended June 30, 2020 and 2019 are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2019 Consolidated Balance Sheets were derived from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other

56

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 — Significant Accounting Policies

interim period or for the fiscal year ending December 31, 2020. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.

COVID-19 (All Registrants)

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

Management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and accompanying notes, and the amounts of revenues and expenses reported during the periods covered by those financial statements and accompanying notes. Management assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, our allowance for credit losses, the carrying value of our goodwill and other long-lived assets, in context with the information reasonably available to us and the unknown future impacts of COVID-19 as of June 30, 2020 and through the date of this report. The Registrants' future assessment of our current expectations of the magnitude and duration of COVID-19, as well as other factors, could result in material impacts to their consolidated financial statements in future reporting periods.

New Accounting Standards (All Registrants)

New Accounting Standards Adopted as of January 1, 2020: The following new authoritative accounting guidance issued by the FASB was adopted as of January 1, 2020 and was reflected by the Registrants in their consolidated financial statements beginning in the first quarter of 2020.

Impairment of Financial Instruments (Issued June 2016). Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects its current estimate of credit losses expected to be incurred over the life of the financial instrument based on historical experience, current conditions and reasonable and supportable forecasts. The standard was effective January 1, 2020 and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. This standard was primarily applicable to Generation's and the Utility Registrants' Customer accounts receivables balances. This guidance did not have a significant impact on the Registrants’ consolidated financial statements.

Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. The standard was effective January 1, 2020 and must be applied on a prospective basis. Exelon, Generation, ComEd, PHI and DPL will apply the new guidance for their goodwill impairment assessments in 2020 and do not expect the updated guidance to have a material impact to their financial statements.

Allowance for Credit Losses on Accounts Receivables (All Registrants)

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

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

57

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 — Significant Accounting Policies

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

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

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

2. Regulatory Matters (All Registrants)

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

Utility Regulatory Matters (Exelon and the Utility Registrants)

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2020.

58

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

Completed Distribution Base Rate Case Proceedings

Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Approved Revenue Requirement (Decrease) Increase			Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois (Electric)(a)	April 8, 2019	$	(6	)	$	(17	)	8.91	%	December 4, 2019	January 1, 2020
DPL - Maryland (Electric)	December 5, 2019 (amended April 23, 2020)	17			12			9.60	%	July 14, 2020	July 16, 2020

__________

(a) Reflects an increase of $51 million for the initial revenue requirement for 2019 and a decrease of $68 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.51%, inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points.

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Requested ROE		Expected Approval Timing
ComEd - Illinois (Electric)(a)	April 16, 2020	$	(11	)	8.38	%	Fourth quarter of 2020
BGE - Maryland (Electric and Natural Gas)(b)	May 15, 2020	235			10.1	%	Fourth quarter of 2020
Pepco - District of Columbia (Electric)(c)	May 30, 2019 (amended June 1, 2020)	136			9.7	%	Fourth quarter of 2020
DPL - Delaware (Natural Gas)(d)	February 21, 2020 (amended March 17, 2020)	9			10.3	%	First quarter of 2021
DPL - Delaware (Electric)(e)	March 6, 2020 (amended April 16, 2020)	24			10.3	%	Second quarter of 2021

__________

(a) Reflects an increase of $51 million for the initial revenue requirement for 2020 and a decrease of $62 million related to the annual reconciliation for 2019. The revenue requirement for 2020 and annual reconciliation for 2019 provides for a weighted average debt and equity return on distribution rate base of 6.28%, inclusive of an allowed ROE of 8.38%, reflecting the average rate on 30-year treasury notes plus 580 basis points.

(b) Reflects a three-year cumulative multi-year plan for 2021 through 2023 and total requested revenue requirement increases in 2023 of $140 million related to electric distribution and $95 million related to natural gas distribution to recover capital investments made in late 2019 and planned capital investments from 2020 to 2023.

(c) Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects a three-year cumulative multi-year plan and requested revenue requirement increases of $73 million and $63 million for 2022 and 2023, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.

(d) The rates will go into effect on September 21, 2020, subject to refund.

(e) The rates will go into effect on October 6, 2020, subject to refund.

Transmission Formula Rates

59

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

Transmission Formula Rate (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or before May 15 and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd, BGE, DPL and ACE is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for Pepco is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense and accumulated deferred income taxes. The update for ComEd, BGE, DPL and ACE also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The update for PECO and Pepco also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).

For 2020, the following total increases/(decreases) were included in ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:

Registrant(a)	Initial Revenue Requirement Increase (Decrease)			Annual Reconciliation Decrease			Total Revenue Requirement Increase (Decrease)(c)			Allowed Return on Rate Base(d)		Allowed ROE(e)
ComEd	$	18		$	(4	)	$	14		8.17	%	11.50	%
PECO(b)	5			(28		)	(23		)	7.47	%	10.35	%
BGE	16			(3		)	4			7.26	%	10.50	%
Pepco	2			(46		)	(44		)	7.81	%	10.50	%
DPL	(4		)	(40		)	(44		)	7.20	%	10.50	%
ACE	5			(25		)	(20		)	7.40	%	10.50	%

__________

(a) All rates are effective June 2020, subject to review by interested parties, which is anticipated to be completed by the fourth quarter of 2020 or first quarter of 2021 for ComEd, BGE, Pepco, DPL and ACE and second quarter of 2021 for PECO.

(b) PECO posted a revised filing to the PJM website on July 17, 2020 reflecting updates to the formula rate based on the FERC order dated July 9, 2020.

(c) The decrease in PECO's transmission revenue requirement relates to refunds from December 1, 2017, in accordance with the settlement agreement dated July 22, 2019. The change in BGE's transmission revenue requirement includes a $9 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE. ComEd, BGE, Pepco, DPL and ACE’s transmission revenue requirement include a decrease related to the April 24, 2020 settlement agreement related to excess deferred income taxes. Refer to Transmission-Related Income Tax Regulatory Assets below for additional information.

(d) Represents the weighted average debt and equity return on transmission rate bases.

(e) As part of the FERC-approved settlements of ComEd’s 2007 and PECO's 2017 transmission rate cases, the rate of return on common equity is 11.50% and 10.35%, respectively, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55% and 55.75%, respectively. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

Other State Regulatory Matters

Illinois Regulatory Matters

Energy Efficiency Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on May 21, 2020.  The filing establishes the revenue requirement used to set the rates that will take effect in January 2021 after the ICC’s review and approval. The revenue requirement requested is based on a reconciliation of the 2019 actual costs plus projected 2020 and 2021 expenditures.

Initial Revenue Requirement Increase		Annual Reconciliation Increase		Total Revenue Requirement Increase			Requested Return on Rate Base		Requested ROE
$	45	$	3	$	48	(a)	6.28	%	8.38	%

__________

(a) The requested revenue requirement increase provides for a weighted average debt and equity return on rate base of 6.28% inclusive of an allowed ROE of 8.38%. The ROE reflects the average rate on 30-year treasury notes plus 580 basis points. The ROE applicable to the 2019 reconciliation year is 8.96% and the return on rate base is 6.56%, which includes a performance adjustment that can either increase or decrease the ROE.

Other Federal Regulatory Matters

Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. In the fourth quarter of 2017, ComEd, BGE, Pepco, DPL, and ACE fully impaired their associated transmission-related income tax regulatory asset for the portion of the income tax regulatory asset that would have been previously amortized.

On February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.

On September 7, 2018, FERC issued orders rejecting 1) BGE's rehearing request of FERC's November 16, 2017 order; and 2) February 23, 2018 (as amended on July 9, 2018) filing by ComEd, Pepco, DPL and ACE for similar recovery.

On November 2, 2018, BGE filed an appeal of FERC’s September 7, 2018 order to the Court of Appeals for the D.C. Circuit. On March 27, 2020, the Court of Appeals denied BGE’s November 2, 2018 appeal.

On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover only ongoing non-TCJA amortization amounts and credit TCJA transmission-related income tax regulatory liabilities to customers for the prospective period starting on October 1, 2018. On April 26, 2019, FERC issued an order accepting ComEd’s, BGE’s, Pepco’s, DPL’s, and ACE’s October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. On April 24, 2020, ComEd, BGE, Pepco, DPL, ACE and other parties filed a settlement agreement with FERC. The settlement agreement provides for the recovery of ongoing transmission-related income tax regulatory assets and establishes the amount and amortization period for excess deferred income taxes resulting from TCJA. The settlement resulted in a reduction to Operating revenues and an offsetting reduction to Income tax expense in the second quarter of 2020.

While FERC has no deadline by which it must rule on the settlement, a final order from FERC is expected in the third quarter of 2020. Exelon cannot predict the outcome of this proceeding. If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be up to approximately $83 million, $51 million, $19 million, $13 million, $5 million, $6 million and $2 million, respectively, as of June 30, 2020.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2019, unless noted below. See Note 3 — Regulatory Matters of the Exelon 2019 Form 10-K for additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets increased $120 million primarily due to an increase of $94 million in the Energy Efficiency Costs regulatory asset and $17 million in the Renewable Energy regulatory asset.

PECO. Regulatory assets increased $55 million primarily due to an increase of $54 million in the Deferred Income Taxes regulatory asset. Regulatory liabilities decreased $81 million primarily due to a decrease of $104 million in the Nuclear Decommissioning regulatory liability offset by a $25 million increase in the Electric Energy and Natural Gas Costs regulatory liability.

ACE. Regulatory liabilities decreased $30 million primarily due to a decrease of $44 million in the Deferred Income Taxes regulatory liability offset by a $18 million increase in Transmission FERC Formula Rate regulatory liability.

Capitalized Ratemaking Amounts Not Recognized (Exelon and the Utility Registrants)

The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.

	Exelon		ComEd(a)		PECO		BGE(b)		PHI		Pepco(c)		DPL(c)		ACE
June 30, 2020	$	57	$	1	$	—	$	49	$	7	$	4	$	3	$	—
December 31, 2019	63		3		—		53		7		4		3		—

_________

(a) Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.

(b) BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.

(c) Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.

Generation Regulatory Matters (Exelon and Generation)

New Jersey Regulatory Matters

New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $17 million and $35 million for the three and six months ended June 30, 2020 and $10 million for the three and six months ended June 30, 2019. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. Exelon and Generation cannot predict the outcome of the appeal. See Note 6 — Early Plant Retirements for additional information related to Salem.

New York Regulatory Matters

New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC to be Generation's FitzPatrick, Ginna and Nine Mile Point nuclear facilities.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

On November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. On October 8, 2019, the court dismissed all remaining claims. The petitioners filed a notice of appeal on November 4, 2019 and originally had until May 4, 2020 to file their brief. Due to COVID-19 related restrictions, the court extended the deadline to July 29, 2020 and, as of August 4, 2020, no brief has been received.

See Note 6 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.

Federal Regulatory Matters

PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR). If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a state government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the MOPR in NYISO applies only to certain resources in downstate New York.

For Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions. While FERC issued a set of orders on MOPR in NYISO on February 20, 2020, it did not expand mitigation to include Generation's nuclear assets in upstate New York. However, FERC has taken action to expand the MOPR in PJM.

On December 19, 2019, FERC required PJM to broadly apply the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage and all resources owned by vertically-integrated utilities. This greatly expands the breadth and scope of PJM’s MOPR, which is effective as of PJM’s next capacity auction. While FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources.

FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism (under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone). In response to FERC’s order PJM submitted a compliance filing on March 18, 2020 wherein PJM proposes tariff language interpreting and implementing FERC's directives and proposes a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing. FERC has no deadline for such action, and FERC could accept, reject or direct further revisions to all or part of PJM's proposed tariff revisions and auction schedule.

On April 16, 2020, FERC issued an order largely denying requests for rehearing of FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing that could also delay the timing for FERC to issue its compliance order(s) which PJM submitted on June 1, 2020. PJM cannot resume activities related to its capacity auctions until FERC acts on these compliance filings.

FERC issued an order on May 21, 2020 involving reforms to PJM’s day-ahead and real-time reserves markets that may require further changes to the MOPR levels pending before FERC in the PJM MOPR Proceeding. In approving reforms to PJM’s reserves markets, FERC also directed PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services (referred to as the Energy and Ancillary Services Offset) and to use that new methodology in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. FERC directed PJM to submit its new Energy and Ancillary Services Offset revenue projection methodology no later than August 5, 2020. On review of this compliance filing, FERC will address how these additional reforms will impact MOPR levels and the timeline for implementing the new revenue projection methodology, including any potential impacts on auction timing.

Unless Illinois and New Jersey can implement an FRR program in their PJM zones, the MOPR will apply in the next capacity auction to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES or the New Jersey ZEC program, as applicable, increasing the risk that those units may not clear the capacity market.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

Exelon is currently working with PJM and other stakeholders to pursue the FRR option prior to the next capacity auction in PJM. If Illinois implements the FRR option, Generation’s Illinois nuclear plants could be removed from PJM’s capacity auction and instead supply capacity and be compensated under the FRR program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 6 - Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative and regulatory changes. Legislation may be introduced in New Jersey as well. Exelon cannot predict whether or when such legislative and regulatory changes can be implemented.

If Generation’s state-supported nuclear plants in PJM are subjected to the MOPR or equivalent without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial statements, which Exelon and Generation cannot reasonably estimate at this time.

Operating License Renewals

Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, Generation has been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.

On October 29, 2019, Generation and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act. Among the Proposed License Articles are modifications to river flows to improve aquatic habitat, eel passage improvements and initiatives to support rare, threatened and endangered wildlife. If FERC approves the Offer of Settlement and incorporates the Proposed License Articles into the new license without modification, then MDE would waive its rights to issue a 401 Certification and Generation would agree, pursuant to a separate agreement with MDE (MDE Settlement), to implement additional environmental protection, mitigation and enhancement measures over the anticipated 50-year term of the new license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. Exelon’s commitments under the various provisions of the Offer of Settlement and MDE Settlement are not effective unless and until FERC approves the Offer of Settlement and issues the new license with the Proposed License Articles. Generation cannot currently predict when FERC will issue the new license.

Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3, which was approved on March 6, 2020. Peach Bottom Units 2 and 3 are now licensed to operate through 2053 and 2054, respectively.

3. Revenue from Contracts with Customers (All Registrants)

The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution and transmission services.

See Note 4 — Revenue from Contracts with Customers of the Exelon 2019 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.

Contract Balances (All Registrants)

Contract Assets and Liabilities

Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Customer accounts receivable, net, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Revenue from Contracts with Customers

Generation records contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. Generation records contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon's and Generation's Consolidated Balance Sheets.

The following table provides a rollforward of the contract assets and liabilities reflected in Exelon's and Generation's Consolidated Balance Sheets for the three and six months ended June 30, 2020 and 2019.

	Contract Assets						Contract Liabilities
	Exelon			Generation			Exelon			Generation
Balance as of December 31, 2019	$	174		$	174		$	33		$	71
Consideration received or due	(19		)	(19		)	20			55
Revenues recognized (a)	17			17			(24		)	(70		)
Balance at March 31, 2020	$	172		$	172		$	29		$	56
Consideration received or due	(26		)	(26		)	13			34
Revenues recognized (a)	13			13			(22		)	(63		)
Balance at June 30, 2020	$	159		$	159		$	20		$	27
				��
Balance as of December 31, 2018	$	187		$	187		$	27		$	42
Consideration received or due	(26		)	(26		)	21			63
Revenues recognized (b)	26			26			(23		)	(66		)
Balance at March 31, 2019	$	187		$	187		$	25		$	39
Consideration received or due	(18		)	(18		)	17			52
Revenues recognized (b)	27			27			(21		)	(65		)
Balance at June 30, 2019	$	196		$	196		$	21		$	26

__________

(a) Revenues recognized in the three and six months ended June 30, 2020, which were included in contract liabilities at December 31, 2019, were approximately $14 million and $23 million, respectively, for Exelon and $42 million and $61 million, respectively, for Generation.

(b) Revenues recognized in the three and six months ended June 30, 2019, which were included in contract liabilities at December 31, 2018, were approximately $9 million and $14 million, respectively, for Exelon and $24 million and $28 million, respectively, for Generation.

The Utility Registrants do not have any contract assets. The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of June 30, 2020 and December 31, 2019, the Utility Registrants' contract liabilities were not material.

Transaction Price Allocated to Remaining Performance Obligations (All Registrants)

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of June 30, 2020. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.

This disclosure excludes Generation's power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.

65

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Revenue from Contracts with Customers

	2020		2021		2022		2023		2024 and thereafter		Total
Exelon	$	169	$	194	$	73	$	43	$	189	$	668
Generation	231		282		105		48		189		855

Revenue Disaggregation (All Registrants)

The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 4 — Segment Information for the presentation of the Registrant's revenue disaggregation.

4. Segment Information (All Registrants)

Operating segments for each of the Registrants are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources at each of the Registrants.

Exelon has 11 reportable segments, which include Generation's 5 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 3 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 5 reportable segments are as follows:

• Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.

• Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.

• New York represents operations within NYISO.

• ERCOT represents operations within Electric Reliability Council of Texas.

• Other Power Regions:

• New England represents the operations within ISO-NE.

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

• West represents operations in the WECC, which includes California ISO.

• Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.

The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the

66

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and six months ended June 30, 2020 and 2019 is as follows:

Three Months Ended June 30, 2020 and 2019

	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations			Exelon
Operating revenues(b):
2020
Competitive businesses electric revenues	$	3,414	$	—	$	—	$	—	$	—	$	—	$	(268	)	$	3,146
Competitive businesses natural gas revenues	353		—		—		—		—		—		—			353
Competitive businesses other revenues	113		—		—		—		—		—		(1		)	112
Rate-regulated electric revenues	—		1,417		586		504		983		—		(15		)	3,475
Rate-regulated natural gas revenues	—		—		95		112		30		—		(1		)	236
Shared service and other revenues	—		—		—		—		3		472		(475		)	—
Total operating revenues	$	3,880	$	1,417	$	681	$	616	$	1,016	$	472	$	(760	)	$	7,322
2019
Competitive businesses electric revenues	$	3,718	$	—	$	—	$	—	$	—	$	—	$	(250	)	$	3,468
Competitive businesses natural gas revenues	333		—		—		—		—		—		—			333
Competitive businesses other revenues	159		—		—		—		—		—		(1		)	158
Rate-regulated electric revenues	—		1,351		566		540		1,063		—		(8		)	3,512
Rate-regulated natural gas revenues	—		—		89		109		24		—		(4		)	218
Shared service and other revenues	—		—		—		—		4		484		(488		)	—
Total operating revenues	$	4,210	$	1,351	$	655	$	649	$	1,091	$	484	$	(751	)	$	7,689
Intersegment revenues(c):
2020	$	271	$	11	$	2	$	4	$	3	$	470	$	(760	)	$	1
2019	252		5		2		6		3		482		(750		)	—
Depreciation and amortization:
2020	$	300	$	274	$	88	$	129	$	191	$	19	$	—		$	1,001
2019	409		257		83		117		188		25		—			1,079

67

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

	Generation		ComEd			PECO			BGE			PHI			Other(a)			Intersegment Eliminations			Exelon
Operating expenses:
2020	$	3,547	$	1,345		$	618		$	573		$	956		$	478		$	(748	)	$	6,769
2019	4,096		1,040			510			569			926			484			(744		)	6,881
Interest expense, net:
2020	$	87	$	98		$	36		$	32		$	67		$	107		$	—		$	427
2019	116		89			33			29			67			75			—			409
Income (loss) before income taxes:
2020	$	860	$	(15	)	$	32		$	17		$	7		$	(108	)	$	1		$	794
2019	202		232			115			56			112			(73		)	—			644
Income Taxes:
2020	$	329	$	46		$	(7	)	$	(22	)	$	(87	)	$	(40	)	$	—		$	219
2019	78		46			13			11			6			(10		)	—			144
Net income (loss):
2020	$	529	$	(61	)	$	39		$	39		$	94		$	(67	)	$	1		$	574
2019	118		186			102			45			106			(63		)	—			494
Capital Expenditures
2020	$	372	$	523		$	253		$	265		$	310		$	34		$	—		$	1,757
2019	383		459			225			284			340			11			—			1,702

__________

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

(b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.

(c) Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Related Party Transactions for additional information on intersegment revenues.

68

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

PHI:

	Pepco			DPL			ACE			Other(a)			Intersegment Eliminations			PHI
Operating revenues(b):
2020
Rate-regulated electric revenues	$	494		$	237		$	256		$	—		$	(4	)	$	983
Rate-regulated natural gas revenues	—			30			—			—			—			30
Shared service and other revenues	—			—			—			97			(94		)	3
Total operating revenues	$	494		$	267		$	256		$	97		$	(98	)	$	1,016
2019
Rate-regulated electric revenues	$	531		$	261		$	274		$	—		$	(3	)	$	1,063
Rate-regulated natural gas revenues	—			24			—			—			—			24
Shared service and other revenues	—			2			—			97			(95		)	4
Total operating revenues	$	531		$	287		$	274		$	97		$	(98	)	$	1,091
Intersegment revenues(c):
2020	$	1		$	2		$	1		$	97		$	(98	)	$	3
2019	1			2			1			98			(99		)	3
Depreciation and amortization:
2020	$	92		$	47		$	44		$	8		$	—		$	191
2019	93			45			40			10			—			188
Operating expenses:
2020	$	436		$	263		$	258		$	97		$	(98	)	$	956
2019	438			243			246			100			(101		)	926
Interest expense, net:
2020	$	34		$	15		$	15		$	3		$	—		$	67
2019	34			15			15			3			—			67
Income (loss) before income taxes:
2020	$	33		$	(9	)	$	(15	)	$	(2	)	$	—		$	7
2019(d)	66			34			14			(2		)	—			112
Income Taxes:
2020	$	(24	)	$	(28	)	$	(33	)	$	(2	)	$	—		$	(87	)
2019	2			4			—			—			—			6
Net income (loss):
2020	$	57		$	19		$	18		$	—		$	—		$	94
2019	64			30			14			(2		)	—			106
Capital Expenditures
2020	$	144		$	89		$	77		$	—		$	—		$	310
2019	154			82			99			5			—			340

__________

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

(b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.

(c) Includes intersegment revenues with ComEd, BGE and PECO, which are eliminated at Exelon.

(d) The Income (loss) before income taxes amounts in Other and Intersegment Eliminations have been adjusted by an offsetting $108 million for consistency with the Exelon consolidating disclosure above.

69

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.

Competitive Business Revenues (Generation):

	Three Months Ended June 30, 2020
	Revenues from external customers(a)							Intersegment Revenues			Total Revenues
	Contracts with customers		Other(b)			Total
Mid-Atlantic	$	1,100	$	(35	)	$	1,065	$	9		$	1,074
Midwest	855		107			962		—			962
New York	336		5			341		(1		)	340
ERCOT	175		52			227		7			234
Other Power Regions	776		43			819		(15		)	804
Total Competitive Businesses Electric Revenues	3,242		172			3,414		—			3,414
Competitive Businesses Natural Gas Revenues	209		144			353		—			353
Competitive Businesses Other Revenues(c)	86		27			113		—			113
Total Generation Consolidated Operating Revenues	$	3,537	$	343		$	3,880	$	—		$	3,880

	Three Months Ended June 30, 2019
	Revenues from external customers(a)						Intersegment revenues			Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	1,162	$	21	$	1,183	$	6		$	1,189
Midwest	974		68		1,042		(8		)	1,034
New York	373		17		390		—			390
ERCOT	178		47		225		4			229
Other Power Regions	814		64		878		(17		)	861
Total Competitive Businesses Electric Revenues	3,501		217		3,718		(15		)	3,703
Competitive Businesses Natural Gas Revenues	177		156		333		15			348
Competitive Businesses Other Revenues(c)	108		51		159		—			159
Total Generation Consolidated Operating Revenues	$	3,786	$	424	$	4,210	$	—		$	4,210

__________

(a) Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.

(b) Includes revenues from derivatives and leases.

(c) Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $21 million and $38 million in 2020 and 2019, respectively, and elimination of intersegment revenues.

70

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

Revenues net of purchased power and fuel expense (Generation):

	Three Months Ended June 30, 2020							Three Months Ended June 30, 2019
	RNF from external customers(a)		Intersegment RNF			Total RNF		RNF from external customers(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	516	$	9		$	525	$	644	$	8		$	652
Midwest	702		1			703		738		(8		)	730
New York	243		3			246		250		3			253
ERCOT	92		5			97		80		(1		)	79
Other Power Regions	181		(24		)	157		154		(20		)	134
Total Revenues net of purchased power and fuel expense for Reportable Segments	1,734		(6		)	1,728		1,866		(18		)	1,848
Other(b)	204		6			210		52		18			70
Total Generation Revenues net of purchased power and fuel expense	$	1,938	$	—		$	1,938	$	1,918	$	—		$	1,918

__________

(a) Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

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

71

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

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

	Three Months Ended June 30, 2020
Revenues from contracts with customers	ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Rate-regulated electric revenues
Residential	$	767		$	377		$	304		$	529		$	237		$	147		$	145
Small commercial & industrial	327			88			51			105			29			39			37
Large commercial & industrial	119			55			94			240			175			22			43
Public authorities & electric railroads	11			7			7			15			8			3			4
Other(a)	218			55			76			161			58			51			53
Total rate-regulated electric revenues(b)	$	1,442		$	582		$	532		$	1,050		$	507		$	262		$	282
Rate-regulated natural gas revenues
Residential	$	—		$	70		$	81		$	17		$	—		$	17		$	—
Small commercial & industrial	—			19			12			8			—			8			—
Large commercial & industrial	—			—			24			1			—			1			—
Transportation	—			6			—			3			—			3			—
Other(c)	—			1			3			1			—			1			—
Total rate-regulated natural gas revenues(d)	$	—		$	96		$	120		$	30		$	—		$	30		$	—
Total rate-regulated revenues from contracts with customers	$	1,442		$	678		$	652		$	1,080		$	507		$	292		$	282
Other revenues
Revenues from alternative revenue programs	$	(25	)	$	4		$	(37	)	$	(64	)	$	(13	)	$	(25	)	$	(26	)
Other rate-regulated electric revenues(e)	—			—			1			—			—			—			—
Other rate-regulated natural gas revenues(e)	—			(1		)	—			—			—			—			—
Total other revenues	$	(25	)	$	3		$	(36	)	$	(64	)	$	(13	)	$	(25	)	$	(26	)
Total rate-regulated revenues for reportable segments	$	1,417		$	681		$	616		$	1,016		$	494		$	267		$	256

72

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

	Three Months Ended June 30, 2019
Revenues from contracts with customers	ComEd			PECO			BGE		PHI			Pepco			DPL		ACE
Rate-regulated electric revenues
Residential	$	647		$	343		$	282	$	494		$	224		$	135	$	135
Small commercial & industrial	349			99			59		120			35			44		41
Large commercial & industrial	127			52			109		278			207			25		46
Public authorities & electric railroads	10			7			6		16			8			4		4
Other(a)	227			62			82		159			56			54		50
Total rate-regulated electric revenues(b)	$	1,360		$	563		$	538	$	1,067		$	530		$	262	$	276
Rate-regulated natural gas revenues
Residential	$	—		$	49		$	60	$	11		$	—		$	11	$	—
Small commercial & industrial	—			33			11		7			—			7		—
Large commercial & industrial	—			—			23		2			—			2		—
Transportation	—			6			—		3			—			3		—
Other(c)	—			1			7		1			—			1		—
Total rate-regulated natural gas revenues(d)	$	—		$	89		$	101	$	24		$	—		$	24	$	—
Total rate-regulated revenues from contracts with customers	$	1,360		$	652		$	639	$	1,091		$	530		$	286	$	276
Other revenues
Revenues from alternative revenue programs	$	(14	)	$	(3	)	$	6	$	(3	)	$	(1	)	$	—	$	(2	)
Other rate-regulated electric revenues(e)	5			6			3		3			2			1		—
Other rate-regulated natural gas revenues(e)	—			—			1		—			—			—		—
Total other revenues	$	(9	)	$	3		$	10	$	—		$	1		$	1	$	(2	)
Total rate-regulated revenues for reportable segments	$	1,351		$	655		$	649	$	1,091		$	531		$	287	$	274

__________

(a) Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.

(b) Includes operating revenues from affiliates of $11 million, $1 million, $3 million, $3 million, $1 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2020 and $5 million, $1 million, $1 million, $3 million, $1 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019.

(c) Includes revenues from off-system natural gas sales.

(d) Includes operating revenues from affiliates of less than $1 million and $1 million at PECO and BGE, respectively, in 2020 and less than $1 million and $4 million at PECO and BGE, respectively, in 2019.

(e) Includes late payment charge revenues.

73

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

Six Months Ended June 30, 2020 and 2019

	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations			Exelon
Operating revenues(b):
2020
Competitive businesses electric revenues	$	7,165	$	—	$	—	$	—	$	—	$	—	$	(594	)	$	6,571
Competitive businesses natural gas revenues	1,025		—		—		—		—		—		(3		)	1,022
Competitive businesses other revenues	423		—		—		—		—		—		(2		)	421
Rate-regulated electric revenues	—		2,856		1,189		1,118		2,086		—		(27		)	7,222
Rate-regulated natural gas revenues	—		—		304		436		94		—		(2		)	832
Shared service and other revenues	—		—		—		—		7		953		(959		)	1
Total operating revenues	$	8,613	$	2,856	$	1,493	$	1,554	$	2,187	$	953	$	(1,587	)	$	16,069
2019
Competitive businesses electric revenues	$	8,052	$	—	$	—	$	—	$	—	$	—	$	(565	)	$	7,487
Competitive businesses natural gas revenues	1,214		—		—		—		—		—		(1		)	1,213
Competitive businesses other revenues	240		—		—		—		—		—		(2		)	238
Rate-regulated electric revenues	—		2,759		1,185		1,198		2,218		—		(17		)	7,343
Rate-regulated natural gas revenues	—		—		369		427		95		—		(8		)	883
Shared service and other revenues	—		—		—		—		6		940		(944		)	2
Total operating revenues	$	9,506	$	2,759	$	1,554	$	1,625	$	2,319	$	940	$	(1,537	)	$	17,166
Intersegment revenues(c):
2020	$	601	$	16	$	4	$	10	$	7	$	949	$	(1,585	)	$	2
2019	568		9		3		12		7		935		(1,534		)	—
Depreciation and amortization:
2020	$	604	$	547	$	173	$	272	$	385	$	42	$	—		$	2,023
2019	814		508		164		252		369		47		—			2,154
Operating expenses:
2020	$	7,947	$	2,497	$	1,242	$	1,263	$	1,955	$	958	$	(1,564	)	$	14,298
2019	9,059		2,174		1,187		1,325		1,981		942		(1,526		)	15,142
Interest expense, net:
2020	$	197	$	192	$	71	$	64	$	134	$	179	$	—		$	837
2019	227		178		67		58		131		152		—			813

74

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

	Generation			ComEd		PECO		BGE		PHI			Other(a)			Intersegment Eliminations			Exelon
Income (loss) before income taxes:
2020	$	313		$	189	$	187	$	237	$	126		$	(175	)	$	2		$	879
2019	854			429		307		253		234			(151		)	—			1,926
Income Taxes:
2020	$	(59	)	$	82	$	9	$	18	$	(76	)	$	(49	)	$	—		$	(75	)
2019	301			85		37		47		11			(27		)	—			454
Net income (loss):
2020	$	368		$	107	$	178	$	219	$	202		$	(126	)	$	2		$	950
2019	540			344		270		206		223			(123		)	—			1,460
Capital Expenditures
2020	$	930		$	1,029	$	512	$	548	$	686		$	68		$	—		$	3,773
2019	890			961		447		542		698			34			—			3,572
Total assets:
June 30, 2020	$	47,003		$	33,896	$	12,120	$	11,027	$	23,004		$	9,288		$	(10,025	)	$	126,313
December 31, 2019	48,995			32,765		11,469		10,634		22,719			8,484			(10,089		)	124,977

__________

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

(b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.

(c) Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Related Party Transactions for additional information on intersegment revenues.

75

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

PHI:

	Pepco			DPL			ACE			Other(a)			Intersegment Eliminations			PHI
Operating revenues(b):
2020
Rate-regulated electric revenues	$	1,039		$	523		$	532		$	—		$	(8	)	$	2,086
Rate-regulated natural gas revenues	—			94			—			—			—			94
Shared service and other revenues	—			—			—			189			(182		)	7
Total operating revenues	$	1,039		$	617		$	532		$	189		$	(190	)	$	2,187
2019
Rate-regulated electric revenues	$	1,106		$	572		$	547		$	—		$	(7	)	$	2,218
Rate-regulated natural gas revenues	—			95			—			—			—			95
Shared service and other revenues	—			—			—			205			(199		)	6
Total operating revenues	$	1,106		$	667		$	547		$	205		$	(206	)	$	2,319
Intersegment revenues(c):
2020	$	3		$	4		$	1		$	189		$	(190	)	$	7
2019	3			3			1			205			(205		)	7
Depreciation and amortization:
2020	$	186		$	94		$	86		$	19		$	—		$	385
2019	186			91			71			20			1			369
Operating expenses:
2020	$	899		$	547		$	509		$	190		$	(190	)	$	1,955
2019	929			550			498			208			(204		)	1,981
Interest expense, net:
2020	$	68		$	31		$	29		$	6		$	—		$	134
2019	68			30			28			5			—			131
Income (loss) before income taxes:
2020	$	90		$	44		$	(1	)	$	(7	)	$	—		$	126
2019(d)	123			94			25			(8		)	—			234
Income Taxes:
2020	$	(19	)	$	(20	)	$	(32	)	$	(5	)	$	—		$	(76	)
2019	4			11			1			(5		)	—			11
Net income (loss):
2020	$	109		$	64		$	31		$	(2	)	$	—		$	202
2019	119			83			24			(3		)	—			223
Capital Expenditures
2020	$	324		$	184		$	178		$	—		$	—		$	686
2019	298			160			227			13			—			698
Total assets:
June 30, 2020	$	8,869		$	4,966		$	4,089		$	5,234		$	(154	)	$	23,004
December 31, 2019(d)	8,661			4,830			3,933			5,335			(40		)	22,719

76

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

__________

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

(b) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.

(c) Includes intersegment revenues with ComEd, BGE and PECO, which are eliminated at Exelon.

(d) The Income (loss) before income taxes and Total assets amounts in Other and Intersegment Eliminations have been adjusted by an offsetting $227 million and $5.7 billion, respectively, for consistency with the Exelon consolidating disclosure above.

The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.

Competitive Business Revenues (Generation):

	Six Months Ended June 30, 2020
	Revenues from external customers(a)							Intersegment Revenues			Total Revenues
	Contracts with customers		Other(b)			Total
Mid-Atlantic	$	2,365	$	(133	)	$	2,232	$	15		$	2,247
Midwest	1,798		172			1,970		(6		)	1,964
New York	672		(16		)	656		(1		)	655
ERCOT	330		81			411		13			424
Other Power Regions	1,782		114			1,896		(21		)	1,875
Total Competitive Businesses Electric Revenues	6,947		218			7,165		—			7,165
Competitive Businesses Natural Gas Revenues	712		313			1,025		—			1,025
Competitive Businesses Other Revenues(c)	185		238			423		—			423
Total Generation Consolidated Operating Revenues	$	7,844	$	769		$	8,613	$	—		$	8,613

	Six Months Ended June 30, 2019
	Revenues from external customers(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other(b)			Total
Mid-Atlantic	$	2,448	$	(2	)	$	2,446	$	(1	)	$	2,445
Midwest	2,030		126			2,156		(14		)	2,142
New York	781		1			782		—			782
ERCOT	307		126			433		8			441
Other Power Regions	1,976		259			2,235		(21		)	2,214
Total Competitive Businesses Electric Revenues	7,542		510			8,052		(28		)	8,024
Competitive Businesses Natural Gas Revenues	763		451			1,214		28			1,242
Competitive Businesses Other Revenues(c)	230		10			240		—			240
Total Generation Consolidated Operating Revenues	$	8,535	$	971		$	9,506	$	—		$	9,506

__________

77

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

(a) Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.

(b) Includes revenues from derivatives and leases.

(c) Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $200 million and losses of $14 million in 2020 and 2019, respectively, and elimination of intersegment revenues.

Revenues net of purchased power and fuel expense (Generation):

	Six Months Ended June 30, 2020							Six Months Ended June 30, 2019
	RNF from external customers(a)		Intersegment RNF			Total RNF		RNF from external customers(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	1,074	$	18		$	1,092	$	1,324	$	10		$	1,334
Midwest	1,431		(4		)	1,427		1,506		(6		)	1,500
New York	433		7			440		512		7			519
ERCOT	168		9			177		178		(24		)	154
Other Power Regions	355		(43		)	312		328		(36		)	292
Total Revenues net of purchased power and fuel expense for Reportable Segments	3,461		(13		)	3,448		3,848		(49		)	3,799
Other(b)	506		13			519		161		49			210
Total Generation Revenues net of purchased power and fuel expense	$	3,967	$	—		$	3,967	$	4,009	$	—		$	4,009

__________

(a) Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

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

78

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

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

	Six Months Ended June 30, 2020
Revenues from contracts with customers	ComEd			PECO		BGE		PHI			Pepco		DPL			ACE
Rate-regulated electric revenues
Residential	$	1,468		$	759	$	644	$	1,062		$	472	$	308		$	282
Small commercial & industrial	689			187		118		221			65		82			74
Large commercial & industrial	253			108		198		493			363		45			85
Public authorities & electric railroads	23			14		14		31			17		6			7
Other(a)	430			113		154		332			119		105			109
Total rate-regulated electric revenues(b)	$	2,863		$	1,181	$	1,128	$	2,139		$	1,036	$	546		$	557
Rate-regulated natural gas revenues
Residential	$	—		$	220	$	287	$	57		$	—	$	57		$	—
Small commercial & industrial	—			70		46		25			—		25			—
Large commercial & industrial	—			—		76		2			—		2			—
Transportation	—			12		—		7			—		7			—
Other(c)	—			2		13		3			—		3			—
Total rate-regulated natural gas revenues(d)	$	—		$	304	$	422	$	94		$	—	$	94		$	—
Total rate-regulated revenues from contracts with customers	$	2,863		$	1,485	$	1,550	$	2,233		$	1,036	$	640		$	557
Other revenues
Revenues from alternative revenue programs	$	(13	)	$	5	$	—	$	(47	)	$	2	$	(24	)	$	(25	)
Other rate-regulated electric revenues(e)	6			3		3		1			1		1			—
Other rate-regulated natural gas revenues(e)	—			—		1		—			—		—			—
Total other revenues	$	(7	)	$	8	$	4	$	(46	)	$	3	$	(23	)	$	(25	)
Total rate-regulated revenues for reportable segments	$	2,856		$	1,493	$	1,554	$	2,187		$	1,039	$	617		$	532

79

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

	Six Months Ended June 30, 2019
Revenues from contracts with customers	ComEd			PECO			BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	1,356		$	752		$	667	$	1,073	$	480	$	320	$	273
Small commercial & industrial	709			195			129		241		73		93		75
Large commercial & industrial	259			100			219		545		411		49		85
Public authorities & electric railroads	23			14			13		31		17		7		7
Other(a)	442			123			160		317		108		101		108
Total rate-regulated electric revenues(b)	$	2,789		$	1,184		$	1,188	$	2,207	$	1,089	$	570	$	548
Rate-regulated natural gas revenues
Residential	$	—		$	247		$	279	$	55	$	—	$	55	$	—
Small commercial & industrial	—			105			46		26		—		26		—
Large commercial & industrial	—			1			73		3		—		3		—
Transportation	—			13			—		7		—		7		—
Other(c)	—			3			13		4		—		4		—
Total rate-regulated natural gas revenues(d)	$	—		$	369		$	411	$	95	$	—	$	95	$	—
Total rate-regulated revenues from contracts with customers	$	2,789		$	1,553		$	1,599	$	2,302	$	1,089	$	665	$	548
Other revenues
Revenues from alternative revenue programs	$	(42	)	$	(6	)	$	17	$	12	$	13	$	1	$	(1	)
Other rate-regulated electric revenues(e)	12			7			6		5		4		1		—
Other rate-regulated natural gas revenues(e)	—			—			3		—		—		—		—
Total other revenues	$	(30	)	$	1		$	26	$	17	$	17	$	2	$	(1	)
Total rate-regulated revenues for reportable segments	$	2,759		$	1,554		$	1,625	$	2,319	$	1,106	$	667	$	547

__________

(a) Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.

(b) Includes operating revenues from affiliates of $16 million, $3 million, $6 million, $7 million, $3 million, $4 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2020 and $9 million, $2 million, $1 million, $7 million, $3 million, $3 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019.

(c) Includes revenues from off-system natural gas sales.

(d) Includes operating revenues from affiliates of less than $1 million and $4 million at PECO and BGE, respectively, in 2020 and $1 million and $9 million at PECO and BGE, respectively, in 2019.

(e) Includes late payment charge revenues.

80

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Accounts Receivable

5. Accounts Receivable (All Registrants)

Allowance for Credit Losses on Accounts Receivable (All Registrants)

The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.

	Three Months Ended June 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI			Pepco			DPL		ACE
Balance as of March 31, 2020	$	278	$	81	$	71	$	66	$	18	$	42		$	15		$	13	$	14
Plus: Current Period Provision for Expected Credit Losses	51		9		7		10		6		19			8			5		6
Less: Write-offs, net of recoveries(a)	12		1		6		5		1		(1		)	(1		)	—		—
Less: Sale of customer accounts receivable (b)	56		56		—		—		—		—			—			—		—
Balance as of June 30, 2020	$	261	$	33	$	72	$	71	$	23	$	62		$	24		$	18	$	20

	Six Months Ended June 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2019	$	243	$	80	$	59	$	55	$	12	$	37	$	13	$	11	$	13
Plus: Current Period Provision for Expected Credit Losses	106		13		25		28		14		26		11		7		8
Less: Write-offs, net of recoveries(a)	32		4		12		12		3		1		—		—		1
Less: Sale of customer accounts receivable (b)	56		56		—		—		—		—		—		—		—
Balance as of June 30, 2020	$	261	$	33	$	72	$	71	$	23	$	62	$	24	$	18	$	20

_________

(a) Recoveries were not material to the Registrants.

(b) See below for additional information on the sale of customer accounts receivable at Generation in the second quarter of 2020.

81

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Accounts Receivable

The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.

	Three Months Ended June 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of March 31, 2020	$	52	$	—	$	22	$	7	$	5	$	18	$	8	$	4	$	6
Plus: Current Period Provision for Expected Credit Losses	12		—		1		1		2		8		3		3		2
Less: Write-offs, net of recoveries(a)	3		—		1		1		1		—		—		—		—
Balance as of June 30, 2020	$	61	$	—	$	22	$	7	$	6	$	26	$	11	$	7	$	8

	Six Months Ended June 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2019	$	48	$	—	$	20	$	7	$	5	$	16	$	7	$	4	$	5
Plus: Current Period Provision for Expected Credit Losses	20		—		4		2		4		10		4		3		3
Less: Write-offs, net of recoveries(a)	7		—		2		2		3		—		—		—		—
Balance as of June 30, 2020	$	61	$	—	$	22	$	7	$	6	$	26	$	11	$	7	$	8

_________

(a) Recoveries were not material to the Registrants.

Unbilled Customer Revenue (All Registrants)

The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets.

	Unbilled customer revenues(a)
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2020	$	804	$	120	$	257	$	120	$	116	$	191	$	102	$	49	$	40
December 31, 2019	1,535		807		218		146		170		194		100		61		33

_________

(a) Unbilled customer revenues are classified in customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.

Sales of Customer Accounts Receivable (Exelon and Generation)

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

82

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Accounts Receivable

On April 8, 2020, Generation derecognized and transferred approximately $1.2 billion of receivables at fair value to the Purchasers in exchange for approximately $500 million in cash purchase price and $650 million of DPP.

The following table summarizes the impact of the sale of certain receivables:

	As of June 30, 2020
Derecognized receivables transferred at fair value(a)	$	1,135
Cash proceeds received	500
DPP	635

_________

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

	Three and six months ended June 30, 2020
Loss on sale of receivables(a)	$	15

_________

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

	Six months ended June 30, 2020
Proceeds from new transfers	$	927
Cash collections received on DPP	1,102
Cash collections reinvested in the Facility	2,029

Generation’s risk of loss following the transfer of accounts receivable is limited to the DPP outstanding.  Payment of DPP is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred, which have historically been and are expected to be immaterial. Generation continues to service the receivables sold in exchange for a servicing fee. Generation did not record a servicing asset or liability as the servicing fees were immaterial.

Generation reflected the cash proceeds received upon sale in Net cash provided by operating activities in the Consolidated Statements of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities of the Consolidated Statements of Cash Flows.

See Note 13 — Fair Value of Financial Assets and Liabilities and Note 16 — Variable Interest Entities for additional information.

Other Purchases and Sales of Customer and Other Accounts Receivables (All Registrants)

Generation is required, under supplier tariffs in ISO-NE, MISO, NYISO and PJM, to sell customer and other receivables to utility companies, which include the Utility Registrants. The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. The following tables present the total receivables purchased and sold.

83

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Accounts Receivable

	Six Months Ended June 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total Receivables Purchased	$	1,584	$	—	$	518	$	494	$	333	$	485	$	303	$	98	$	84
Total Receivables Sold	533		779		—		—		—		—		—		—		—
Related Party Transactions:
Receivables purchased from Generation	—		—		34		67		73		72		51		13		8
Receivables sold to the Utility Registrants	—		246		—		—		—		—		—		—		—

6. Early Plant Retirements (Exelon and Generation)

Exelon and Generation continuously evaluate factors that affect the current and expected economic value of Generation’s plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, just prior to its next scheduled nuclear refueling outage.

Nuclear Generation

In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York and Three Mile Island nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision-making authority to retire Salem.

Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program and the New York CES, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Salem, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent the Illinois ZES, New Jersey ZEC program or the New York CES do not operate as expected over their full terms, each of these plants could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. In addition, FERC’s December 19, 2019 order on the MOPR in PJM may undermine the continued effectiveness of the Illinois ZES and the New Jersey ZEC program unless Illinois and New Jersey implement an FRR mechanism under which the Generation plants in these states would be removed from PJM’s capacity auction. See Note 2 — Regulatory Matters for additional information on the New Jersey ZEC program, New York CES and FERC's December 19, 2019 order and Note 3 — Regulatory Matters of the 2019 Form 10-K for additional information on the Illinois ZES.

In Pennsylvania, the TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Generation announced that it would permanently cease generation operations at TMI. On September 20, 2019, Generation permanently ceased generation operations at TMI.

84

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Early Plant Retirements

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

Income statement expense (pre-tax)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Depreciation and amortization
Accelerated depreciation	$	71	$	145
Accelerated nuclear fuel amortization	4		9
Operating and maintenance(a)	—		(83		)
Total	$	75	$	71

_________

(a) Primarily reflects the net impacts associated with the remeasurement of the TMI ARO. See Note 9 — Asset Retirement Obligations of the 2019 Form 10-K for additional information.

Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. While all of LaSalle's capacity did clear in the 2021-2022 planning year auction, Generation has become increasingly concerned about the economic viability of this plant as well in a landscape where energy market prices remain depressed and energy market rules remain fatally flawed. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level. The absence of such solutions or reforms could result in future impairments of the Midwest asset group, or accelerated depreciation for specific plants over their shortened estimated useful lives, both of which could have a material unfavorable impact on Exelon's and Generation's future results of operations.

The following table provides the balance sheet amounts as of June 30, 2020 for Exelon's and Generation's significant assets and liabilities associated with these four nuclear plants. Depreciation provisions are based on the estimated useful lives of these nuclear generating stations, which reflect the first renewal of the operating licenses.

	Dresden			Byron			Braidwood			LaSalle			Total
Asset Balances
Materials and supplies inventory, net	$	70		$	70		$	82		$	108		$	330
Nuclear fuel inventory, net	182			145			180			244			751
Completed plant, net	1,057			1,334			1,416			1,588			5,395
Construction work in progress	18			21			18			19			76
Liability Balances
Asset retirement obligation	(1,317		)	(604		)	(562		)	(915		)	(3,398		)
NRC License First Renewal Term	2029 (Unit 2)			2044 (Unit 1)			2046 (Unit 1)			2042 (Unit 1)
	2031 (Unit 3)			2046 (Unit 2)			2047 (Unit 2)			2043 (Unit 2)

Other Generation

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

85

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Early Plant Retirements

On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service agreement, reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. Those adjustments were reflected in a compliance filing filed March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings in the order. On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the Everett Marine Terminal. FERC directed a downward adjustment to the rate base for Mystic Units 8 and 9, the effect of which will be partially offset by elimination of a crediting mechanism for third party gas sales during the term of the cost of service agreement. A compliance filing will be due on September 15, 2020. On July 28, 2020, FERC ordered additional briefings in the ROE proceeding, with initial briefs due by September 28, 2020.

On March 25, 2019, ISO-NE filed the Inventoried Energy Program (IEP), which is intended to provide an interim fuel security program pending conclusion of the stakeholder process to develop a long-term, market-based solution to address fuel security. The IEP went into effect by operation of law on August 5, 2019 because FERC did not have a quorum at that time. On October 7, 2019, requests for rehearing were denied and several parties appealed to the D.C. Circuit Court. On April 14, 2020, FERC filed an unopposed motion asking the court for a voluntary remand of the IEP order, noting that FERC now has a quorum of commissioners who can participate in the consideration of ISO-NE’s IEP filing. On April 21, 2020, the D.C. Circuit Court granted the voluntary remand and on June 18, 2020, FERC issued an order finding the IEP just and reasonable and accepting ISO-NE's proposed tariff revisions. Several parties have filed requests for rehearing.

On April 15, 2020, ISO-NE filed its long-term, market-based fuel security proposal, proposing three new, day-ahead ancillary services products intended to compensate generators for operational capabilities that provide fuel security to the region. In the filing, ISO-NE also proposed to sunset the Fuel Security Retention Mechanism, through which Mystic has been retained for fuel security, and the IEP by June 1, 2024. In addition, the filing includes an alternate proposal sponsored by New England Power Pool (NEPOOL), which includes substantive amendments to the ISO-NE proposal. On May 15, 2020, Exelon filed a limited protest to ISO's long-term fuel-security proposal asking FERC to accept ISO-NE's proposal but to direct ISO-NE to revise its tariff so that the IEP remains in place as a safeguard until the long-term solution is in place. A number of other comments in support and protests have been filed. ISO-NE asked for a decision on its proposal by November 1, 2020.

On June 12, 2020, Generation filed a complaint with FERC against ISO-NE on the grounds that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic for transmission security for the 2024 to 2025 Capacity Commitment Period (FCA 15) and that modifications ISO-NE made to its unfiled planning procedures to avoid retaining Mystic should have been filed with FERC for approval. Generation asked for a ruling from FERC by August 10, 2020, but ISO-NE asserts that a ruling is not needed until November 2, 2020. On July 27, 2020, ISO-NE issued a memo to NEPOOL announcing its determination pursuant to its unfiled planning procedures that Mystic Units 8 and 9 are not needed for FCA 15 for transmission security. It had previously determined Mystic Units 8 and 9 are not needed for fuel security. The timing and the outcome of this proceeding is uncertain.

The following table provides the balance sheet amounts as of June 30, 2020 for Exelon's and Generation’s significant assets and liabilities associated with the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by the failure to adopt long-term solutions for reliability and fuel security.

	June 30, 2020
Asset Balances
Materials and supplies inventory	$	33
Fuel inventory	6
Property, plant and equipment, net	898
Liability Balances
Asset retirement obligation	(3		)

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

86

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Nuclear Decommissioning

7. Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC within Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2019 to June 30, 2020:

Nuclear decommissioning ARO at December 31, 2019 (a)	$	10,504
Accretion expense	243
Costs incurred related to decommissioning plants	$	(37	)
Nuclear decommissioning ARO at June 30, 2020 (a)	$	10,710

_________

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

NDT Funds

Exelon and Generation had NDT funds totaling $12,917 million and $13,353 million at June 30, 2020 and December 31, 2019, respectively. The NDT funds also include $187 million and $163 million for the current portion of the NDT funds at June 30, 2020 and December 31, 2019, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 17 — Supplemental Financial Information for additional information on activities of the NDT funds.

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.

Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for all units, including its shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the April 1, 2019 submittal. On March 31, 2020, Generation filed its annual decommissioning funding status report with the NRC for Generation’s shutdown units (excluding Zion Station for the reason noted above). The annual status report demonstrated adequate decommissioning funding assurance as of December 31, 2019, for all of its shutdown reactors except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff.  See Note 9 — Asset Retirement

87

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Nuclear Decommissioning

Obligations of the Exelon 2019 Form 10-K for information regarding the amount collected from PECO ratepayers for decommissioning cost.

8. Asset Impairments (Exelon and Generation)

The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.

Antelope Valley Solar Facility

Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of June 30, 2020, Generation had approximately $710 million of net long-lived assets related to Antelope Valley. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and no impairment charge was recorded.

Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,840 million of additional net long-lived assets as of June 30, 2020. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling interests. To date, there have been no indicators to suggest that the carrying amount of other net long-lived assets of EGR IV may not be recoverable.

The United States Bankruptcy Court entered an order on June 20, 2020 confirming PG&E’s plan of reorganization. On July 1, 2020 the plan became effective, and PG&E emerged from bankruptcy. Under the confirmed plan, PG&E will continue to honor the existing PPA agreement with Antelope Valley.

See Note 12 - Debt and Credit Agreements for additional information.

New England Asset Group

During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation notified ISO-NE of the early retirement of its Mystic Generating Station's Units 7, 8, 9 and the Mystic Jet Unit (Mystic Generating Station assets) absent regulatory reforms. These events suggested that the carrying value of its New England asset group may be impaired. In the second quarter of 2018, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and no impairment charge was required. Generation continues to monitor developments in the region that would indicate a potential triggering event for impairment and continues to look for solutions that appropriately compensate both Mystic 8 and 9 and the Everett Marine Terminal for their contributions to the region. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in material future impairments of the New England asset group. See Note 6 - Early Plant Retirements for additional information.

Midwest Asset Group

We continue to monitor the recoverability of the carrying value of the Midwest asset group as certain nuclear plants in Illinois are showing increased signs of economic distress, which could lead to an early retirement. See Note 6 - Early Plant Retirements for additional information.

88

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Income Taxes

9. Income Taxes (All Registrants)

Rate Reconciliation

The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:

	Three Months Ended June 30, 2020
	Exelon(a)	Generation(a)	ComEd(b)	PECO(c)	BGE(c)	PHI(c)	Pepco(c)	DPL(d)	ACE(d)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.8	3.1	(131.7)	(9.7)	3.8	(25.8)	2.1	6.7	7.2
Qualified NDT fund income	18.8	17.3	—	—	—	—	—	—	—
Deferred Prosecution Agreement payments	5.3	—	(288.3)	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.6)	(0.5)	2.9	—	(0.2)	(2.2)	(0.1)	0.5	0.3
Plant basis differences	(1.6)	—	2.4	(23.6)	(13.4)	(44.7)	(3.9)	(1.1)	10.0
Production tax credits and other credits	(1.4)	(1.2)	3.3	—	(1.0)	(0.7)	(0.1)	0.1	—
Noncontrolling interests	0.1	0.1	—	—	—	—	—	—	—
Excess deferred tax amortization	(15.5)	—	116.0	(4.8)	(137.9)	(1,358.5)	(89.0)	284.0	174.5
Tax Settlements	(1.9)	(1.8)	—	—	—	—	—	—	—
Other	(0.4)	0.3	(32.3)	(4.8)	(1.7)	168.0	(2.7)	(0.1)	7.0
Effective income tax rate	27.6%	38.3%	(306.7)%	(21.9)%	(129.4)%	(1,242.9)%	(72.7)%	311.1%	220.0%

_________

(a) At Exelon and Generation, positive percentages represent income tax expense.

(b) ComEd recognized a loss before income taxes for the three months ended June 30, 2020. As a result, negative percentages represent income tax expense. The higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 14 — Commitments and Contingencies for additional information.

(c) At PECO, BGE, PHI, and Pepco, negative percentages represent an income tax benefit. At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm repairs. At BGE, PHI, and Pepco, the lower effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 2 — Regulatory Matters for additional information.

(d) DPL and ACE recognized a loss before income taxes for the three months ended June 30, 2020. As a result, positive percentages represent an income tax benefit. At DPL and ACE, the higher effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 2 — Regulatory Matters for additional information.

89

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Income Taxes

	Three Months Ended June 30, 2019
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	5.4	5.5	8.2	(1.2)	6.5	4.8	2.0	7.0	7.0
Qualified NDT fund income	5.1	16.2	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.7)	(1.9)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.7)	—	(0.6)	(5.9)	(1.5)	(1.7)	(2.1)	(0.3)	(2.2)
Production tax credits and other credits	(0.9)	(2.8)	—	—	(0.1)	—	—	—	—
Noncontrolling interests	0.1	0.4	—	—	—	—	—	—	—
Excess deferred tax amortization	(7.8)	—	(9.0)	(2.7)	(7.9)	(19.4)	(18.3)	(15.7)	(23.1)
Other	1.9	0.2	0.4	0.1	1.7	0.9	0.5	—	(2.4)
Effective income tax rate	22.4%	38.6%	19.8%	11.3%	19.6%	5.4%	3.0%	11.8%	—%

90

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Income Taxes

	Six Months Ended June 30, 2020
	Exelon	Generation(a)	ComEd(b)	PECO(c)	BGE(d)	PHI(d)	Pepco(d)	DPL(d)	ACE(e)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	6.7	7.2	19.1	(1.6)	5.6	4.3	3.7	6.5	12.4
Qualified NDT fund income	(5.7)	(16.0)	—	—	—	—	—	—	—
Deferred Prosecution Agreement payments	4.8	—	22.2	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.0)	(2.3)	(0.4)	—	(0.1)	(0.2)	(0.1)	(0.3)	7.2
Plant basis differences	(3.7)	—	(1.4)	(11.0)	(2.0)	(3.5)	(2.7)	(0.6)	146.2
Production tax credits and other credits	(2.2)	(5.5)	(0.4)	—	(0.2)	(0.1)	(0.1)	—	0.7
Noncontrolling interests	1.1	3.2	—	—	—	—	—	—	—
Excess deferred tax amortization	(20.9)	—	(20.2)	(3.3)	(16.1)	(80.3)	(41.6)	(72.9)	2,613.8
Tax Settlements	(9.3)	(26.1)	—	—	—	—	—	—	—
Other	0.7	(0.3)	3.5	(0.3)	(0.6)	(1.5)	(1.3)	0.8	398.7
Effective income tax rate	(8.5)%	(18.8)%	43.4%	4.8%	7.6%	(60.3)%	(21.1)%	(45.5)%	3,200.0%

_________

(a) At Generation, the lower effective tax rate is primarily attributable to tax settlements.

(b) At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 14 — Commitments and Contingencies for additional information.

(c) At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm repairs.

(d) At BGE, PHI, Pepco, and DPL, the lower effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 2 — Regulatory Matters for additional information.

(e) ACE recognized a loss before income taxes for the six months ended June 30, 2020. As a result, a positive percentage at ACE represents an income tax benefit for the period presented. At ACE, the higher effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 2 — Regulatory Matters for additional information.

91

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Income Taxes

	Six Months Ended June 30, 2019
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	4.4	3.6	8.2	0.2	6.4	4.7	2.0	6.7	6.9
Qualified NDT fund income	6.5	14.7	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.6)	(1.1)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.5)	—	(0.6)	(6.4)	(1.0)	(1.7)	(2.0)	(0.6)	(2.2)
Production tax credits and other credits	(0.8)	(1.8)	—	—	—	—	—	—	—
Noncontrolling interests	(0.3)	(0.8)	—	—	—	—	—	—	—
Excess deferred tax amortization	(5.8)	—	(8.8)	(2.6)	(7.9)	(19.4)	(18.1)	(15.6)	(23.4)
Other	0.7	(0.4)	0.2	(0.1)	0.2	0.3	0.5	0.4	2.0
Effective income tax rate	23.6%	35.2%	19.8%	12.1%	18.6%	4.7%	3.3%	11.7%	4.0%

92

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Income Taxes

Accounting for Uncertainty in Income Taxes

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

	Exelon		Generation		PHI		ACE
June 30, 2020	$	122	$	49	$	50	$	15
December 31, 2019	507		441		48		14

Exelon's and Generation's unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase to Exelon's and Generation’s net income of $76 million and $73 million, respectively, in the first quarter of 2020, reflecting a decrease to Exelon's and Generation's income tax expense of $67 million.

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

The following table represents Exelon's, PHI's and ACE's unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, and the outcomes of pending court cases as of June 30, 2020. Generation's, ComEd's, PECO's, BGE's, Pepco's and DPL's amounts are not material.

Exelon		PHI		ACE(a)
$	14	$	14	$	14

_________

(a) The unrecognized tax benefit related to ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Other Income Tax Matters

State Income Tax Law Changes

On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation and ComEd do not expect a material impact to their financial statements as a result of the rate change.

10. Retirement Benefits (All Registrants)

Defined Benefit Pension and OPEB

During the first quarter of 2020, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2020. This valuation resulted in an increase to the pension and OPEB obligations of $8 million and $31 million, respectively. Additionally, accumulated other comprehensive loss increased by $7 million (after-tax) and regulatory assets and liabilities increased by $19 million and decreased by $10 million, respectively.

The majority of the 2020 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.34%. The majority of the 2020 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.69% for funded plans and a discount rate of 3.31%.

93

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Retirement Benefits

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and six months ended June 30, 2020 and 2019.

	Pension Benefits Three Months Ended June 30,						OPEB Three Months Ended June 30,
	2020			2019			2020			2019
Components of net periodic benefit cost:
Service cost	$	96		$	89		$	22		$	24
Interest cost	190			221			39			47
Expected return on assets	(318		)	(306		)	(40		)	(38		)
Amortization of:
Prior service cost (benefit)	1			—			(31		)	(44		)
Actuarial loss	128			103			12			10
Settlement charges	6			—			—			—
Net periodic benefit cost	$	103		$	107		$	2		$	(1	)

	Pension Benefits Six Months Ended June 30,						OPEB Six Months Ended June 30,
	2020			2019			2020			2019
Components of net periodic benefit cost:
Service cost	$	193		$	178		$	45		$	47
Interest cost	379			442			77			94
Expected return on assets	(636		)	(612		)	(81		)	(77		)
Amortization of:
Prior service cost (benefit)	2			—			(62		)	(89		)
Actuarial loss	256			206			24			23
Settlement charges	6			—			—			—
Net periodic benefit cost	$	200		$	214		$	3		$	(2	)

The amounts below represent the Registrants' allocated pension and OPEB plan costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For Generation and the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant and equipment, net in their consolidated financial statements.

	Three Months Ended June 30,				Six Months Ended June 30,
Pension and OPEB Costs	2020		2019		2020		2019
Exelon	$	105	$	106	$	203	$	212
Generation	32		31		59		62
ComEd	28		23		57		47
PECO	1		3		3		5
BGE	16		16		31		30
PHI	18		24		35		48
Pepco	4		6		7		12
DPL	2		4		4		8
ACE	3		4		7		8

94

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Retirement Benefits

Defined Contribution Savings Plans

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

	Three Months Ended June 30,				Six Months Ended June 30,
Savings Plan Matching Contributions	2020		2019		2020		2019
Exelon	$	34	$	33	$	67	$	64
Generation	14		14		27		28
ComEd	9		9		16		16
PECO	2		2		5		5
BGE	2		2		4		4
PHI	3		3		6		6
Pepco	1		1		2		2
DPL	—		1		1		1
ACE	1		—		1		1

11. Derivative Financial Instruments (All Registrants)

The Registrants use derivative instruments to manage commodity price risk, interest rate risk and foreign exchange risk related to ongoing business operations.

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at Generation and are offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.

Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below that present fair value balances, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.

Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

Commodity Price Risk (All Registrants)

Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and commodity products.

95

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.

Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.

Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.

Registrant	Commodity	Accounting Treatment	Hedging instrument
ComEd	Electricity	NPNS	Fixed price contracts based on all requirements in the IPA procurement plans.
	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)	20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO(b)	Gas	NPNS	Fixed price contracts to cover about 20% of planned natural gas purchases in support of projected firm sales.
BGE	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
Pepco	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
DPL	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed and Index priced contracts through full requirements contracts.
		Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(c)	Exchange traded future contracts for 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE	Electricity	NPNS	Fixed price contracts for all BGS requirements through full requirements contracts.

__________

(a) See Note 3 - Regulatory Matters of the 2019 Form 10-K for additional information.

(b) As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.

(c) The fair value of the DPL economic hedge is not material as of June 30, 2020 and December 31, 2019 and is not presented in the fair value tables below.

96

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation and ComEd as of June 30, 2020 and December 31, 2019:

June 30, 2020	Exelon			Generation														ComEd
Derivatives	Total Derivatives			Economic Hedges			Proprietary Trading			Collateral  (a)(b)		Netting (a)			Subtotal			Economic Hedges
Mark-to-market derivative assets (current assets)	$	570		$	3,240		$	70		$	179	$	(2,919	)	$	570		$	—
Mark-to-market derivative assets (noncurrent assets)	466			1,582			20			77		(1,213		)	466			—
Total mark-to-market derivative assets	1,036			4,822			90			256		(4,132		)	1,036			—
Mark-to-market derivative liabilities (current liabilities)	(190		)	(3,243		)	(46		)	211		2,919			(159		)	(31		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(421		)	(1,442		)	(14		)	109		1,213			(134		)	(287		)
Total mark-to-market derivative liabilities	(611		)	(4,685		)	(60		)	320		4,132			(293		)	(318		)
Total mark-to-market derivative net assets (liabilities)	$	425		$	137		$	30		$	576	$	—		$	743		$	(318	)

December 31, 2019	Exelon			Generation														ComEd
Description	Total Derivatives			Economic Hedges			Proprietary Trading			Collateral (a)(b)		Netting (a)			Subtotal			Economic Hedges
Mark-to-market derivative assets (current assets)	$	675		$	3,506		$	72		$	287	$	(3,190	)	$	675		$	—
Mark-to-market derivative assets (noncurrent assets)	508			1,238			25			122		(877		)	508			—
Total mark-to-market derivative assets	1,183			4,744			97			409		(4,067		)	1,183			—
Mark-to-market derivative liabilities (current liabilities)	(236		)	(3,713		)	(38		)	357		3,190			(204		)	(32		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(380		)	(1,140		)	(11		)	163		877			(111		)	(269		)
Total mark-to-market derivative liabilities	(616		)	(4,853		)	(49		)	520		4,067			(315		)	(301		)
Total mark-to-market derivative net assets (liabilities)	$	567		$	(109	)	$	48		$	929	$	—		$	868		$	(301	)

_________

(a) Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are not material and not reflected in the table above.

(b) Of the collateral posted/(received), $383 million and $511 million represents variation margin on the exchanges at June 30, 2020 and December 31, 2019 respectively.

97

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

Economic Hedges (Commodity Price Risk)

Generation. For the three and six months ended June 30, 2020 and 2019, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.

	Three Months Ended June 30,					Six Months Ended June 30,
	2020		2019			2020		2019
Income Statement Location	Gain (Loss)					Gain (Loss)
Operating revenues	$	24	$	40		$	199	$	(10	)
Purchased power and fuel	63		(114		)	15		(84		)
Total Exelon and Generation	$	87	$	(74	)	$	214	$	(94	)

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of June 30, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 98%-101% and 76%-79% for 2020 and 2021, respectively.

Proprietary Trading (Commodity Price Risk)

Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the three and six months ended June 30, 2020 and 2019, net pre-tax commodity mark-to-market gains (losses) for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Exelon and Generation utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $1,219 million and $1,269 million at June 30, 2020 and December 31, 2019, respectively, for Exelon and $519 million and $569 million at June 30, 2020 and December 31, 2019, respectively, for Generation.

Generation utilizes foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, which are treated as economic hedges. The notional amounts were $160 million and $231 million at June 30, 2020 and December 31, 2019, respectively.

The mark-to-market derivative assets and liabilities as of June 30, 2020 and December 31, 2019 and the mark-to-market gains and losses for the three and six months ended June 30, 2020 and 2019 were not material for Exelon and Generation.

Credit Risk (All Registrants)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date.

Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a

98

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

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

The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2020. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges. 

Rating as of June 30, 2020	Total Exposure Before Credit Collateral		Credit Collateral(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	772	$	25	$	747	1	$	117
Non-investment grade	35		26		9
No external ratings
Internally rated — investment grade	213		1		212
Internally rated — non-investment grade	130		17		113
Total	$	1,150	$	69	$	1,081	1	$	117

 

Net Credit Exposure by Type of Counterparty	As of June 30, 2020
Financial institutions	$	29
Investor-owned utilities, marketers, power producers	834
Energy cooperatives and municipalities	173
Other	45
Total	$	1,081

_________ 

(a) As of June 30, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $38 million of letters of credit. The credit collateral does not include non-liquid collateral.

Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of June 30, 2020, the Utility Registrants’ counterparty credit risk with suppliers was not material.

Credit-Risk-Related Contingent Features (All Registrants)

Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support

99

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

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

The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:

Credit-Risk Related Contingent Features	June 30, 2020			December 31, 2019
Gross fair value of derivative contracts containing this feature(a)	$	(969	)	$	(956	)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)	697			649
Net fair value of derivative contracts containing this feature(c)	$	(272	)	$	(307	)

_________

(a) Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.

(b) Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.

(c) Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

As of June 30, 2020 and December 31, 2019, Exelon and Generation posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

	June 30, 2020		December 31, 2019
Cash collateral posted	$	645	$	982
Letters of credit posted	224		264
Cash collateral held	110		103
Letters of credit held	76		112
Additional collateral required in the event of a credit downgrade below investment grade	1,319		1,509

Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.

Utility Registrants

The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral.

PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE, and DPL’s credit rating. As of June 30, 2020, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE or DPL lost their investment grade

100

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

credit ratings as of June 30, 2020, they could have been required to post incremental collateral to its counterparties of $24 million, $26 million and $10 million, respectively.

12. Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

Exelon Corporate, ComEd and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

Commercial Paper

The following table reflects the Registrants' commercial paper programs as of June 30, 2020 and December 31, 2019. PECO had no commercial paper borrowings as of both June 30, 2020 and December 31, 2019.

	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	June 30, 2020		December 31, 2019		June 30, 2020		December 31, 2019
Exelon(a)	$	19	$	870	0.15	%	2.25	%
Generation	—		320		—	%	1.84	%
ComEd	—		130		—	%	2.38	%
BGE	—		76		—	%	2.46	%
PHI(b)	19		208		0.15	%	N/A
PEPCO	14		82		0.15	%	2.56	%
DPL	—		56		—	%	2.02	%
ACE	5		70		0.15	%	2.43	%

__________

(a) Includes outstanding commercial paper at Exelon Corporate of $136 million with average interest rates on commercial paper borrowings of 1.92% at December 31, 2019. Exelon Corporate had no outstanding commercial paper borrowings as of June 30, 2020.

(b) Includes the consolidated amounts of Pepco, DPL, and ACE.

On March 19, 2020, Generation borrowed $1.5 billion on its revolving credit facility due to disruptions in the commercial paper markets as a result of COVID-19. The funds were used to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020. As of June 30, 2020, the available capacity on Generation’s revolving credit facility was $5 billion. See Note 16— Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on the Registrants’ credit facilities.

Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed on March 19, 2020 and will expire on March 18, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-term borrowings.

On March 19, 2020, Generation entered into a term loan agreement for $200 million. The loan agreement has an expiration of March 18, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.50% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.

101

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 12 — Debt and Credit Agreements

On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement has an expiration of March 30, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.75% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.

Revolving Credit Agreements

On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility at a variable interest rate of LIBOR plus 1.75%. This facility will be used by Exelon as an additional source of short-term liquidity as needed.

Bilateral Credit Agreements

On May 15, 2020, Generation entered into a credit agreement establishing a $100 million bilateral credit facility. This facility will solely be used by Generation to issue letters of credit, and the maturity date is automatically renewed based on the contingency standards set within the agreement.

During the second quarter of 2020, CENG drew on its bilateral credit facility. As of June 30, 2020, there was $100 million outstanding at this facility. The bilateral credit facility with CENG is incorporated within Generation, and supports the issuance of letters of credit and funding for working capital.

102

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 12 — Debt and Credit Agreements

Long-Term Debt

Issuance of Long-Term Debt

During the six months ended June 30, 2020, the following long-term debt was issued:

Company(a)	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Exelon	Notes	4.05	%	April 15, 2030	$	1,250	Repay existing indebtedness and for general corporate purposes.
Exelon	Notes	4.70	%	April 15, 2050	750		Repay existing indebtedness and for general corporate purposes.
Generation	Senior Notes	3.25	%	June 1, 2025	900		Repay existing indebtedness and for general corporate purposes.
Generation	Energy Efficiency Project Financing(b)	3.95	%	August 31, 2020	2		Funding to install energy conservation measures for the Fort Meade project.
Generation	Energy Efficiency Project Financing(b)	2.53	%	April 30, 2021	1		Funding to install energy conservation measures for the Fort AP Hill project.
ComEd	First Mortgage Bonds, Series 128	2.20	%	March 1, 2030	350		Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes.
ComEd	First Mortgage Bonds, Series 129	3.00	%	March 1, 2050	650		Repay a portion of outstanding commercial paper obligations and to fund general corporate purposes.
PECO	First and Refunding Mortgage Bonds	2.80	%	June 15, 2050	350		Funding for general corporate purposes.
BGE	Senior Notes	2.90	%	June 15, 2050	400		Repay commercial paper obligations and for general corporate purposes.
Pepco(c)	First Mortgage Bonds	2.53	%	February 25, 2030	150		Repay existing indebtedness and for general corporate purposes.
DPL	First Mortgage Bonds	2.53	%	June 9, 2030	100		Repay existing indebtedness and for general corporate purposes.
ACE	Tax-Exempt First Mortgage Bonds	2.25	%	June 1, 2029	23		Refinance existing indebtedness.
ACE	First Mortgage Bonds	3.24	%	June 9, 2050	100		Repay existing indebtedness and for general corporate purposes.

__________

(a) On July 1, 2020, DPL issued $78 million of tax-exempt bonds maturing on January 1, 2031. The bonds have a 1.05% interest rate through July 2025.

(b) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

(c) On February 25, 2020, Pepco entered into a purchase agreement of First Mortgage Bonds for $150 million at 3.28% due on September 23, 2050. The closing date of the issuance is expected to occur in September 2020.

Debt Covenants

As of June 30, 2020, the Registrants are in compliance with debt covenants.

Nonrecourse Debt

Exelon and Generation have issued nonrecourse debt financing. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default.

Antelope Valley Solar Ranch One.  In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037.

103

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 12 — Debt and Credit Agreements

As of June 30, 2020, approximately $475 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the project. As of June 30, 2020, Generation had $37 million in letters of credit outstanding related to the project. In 2017, Generation’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.

Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code, which created an event of default for Antelope Valley’s nonrecourse debt that provided the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the event of default and in the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019. Further, distributions from Antelope Valley to EGR IV were suspended.

The United States Bankruptcy Court entered an order on June 20, 2020 confirming PG&E’s plan of reorganization. On July 1, 2020 the plan became effective, and PG&E emerged from bankruptcy. On July 21, 2020, Antelope Valley received a waiver from the DOE for the event of default and, as such, the debt has been classified as noncurrent as of June 30, 2020 and distributions from Antelope Valley to EGR IV are now permitted.

See Note 8 — Asset Impairments for additional information.

ExGen Renewables IV.  In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this financing. The loan is scheduled to mature on November 28, 2024. As of June 30, 2020, approximately $775 million was outstanding.

See Note 16— Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on nonrecourse debt.

13. Fair Value of Financial Assets and Liabilities (All Registrants)

Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

• Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.

• Level 2 - inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

• Level 3 - unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

104

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

Fair Value of Financial Liabilities Recorded at Amortized Cost

The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of June 30, 2020 and December 31, 2019. The Registrants have no financial liabilities classified as Level 1.

The carrying amounts of the Registrants’ short-term liabilities as presented on their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.

	June 30, 2020								December 31, 2019
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
			Level 2		Level 3		Total				Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year(a)
Exelon	$	38,626	$	41,531	$	3,080	$	44,611	$	36,039	$	37,453	$	2,580	$	40,033
Generation	7,433		6,761		1,418		8,179		7,974		7,304		1,366		8,670
ComEd	9,480		11,433		—		11,433		8,491		9,848		—		9,848
PECO	3,752		4,453		50		4,503		3,405		3,868		50		3,918
BGE	3,663		4,203		—		4,203		3,270		3,649		—		3,649
PHI	6,890		6,016		1,612		7,628		6,563		5,902		1,164		7,066
Pepco	3,013		3,270		576		3,846		2,864		3,198		388		3,586
DPL	1,675		1,444		443		1,887		1,567		1,408		311		1,719
ACE	1,420		1,040		593		1,633		1,327		1,026		464		1,490
Long-Term Debt to Financing Trusts(a)
Exelon	$	390	$	—	$	409	$	409	$	390	$	—	$	428	$	428
ComEd	205		—		216		216		205		—		227		227
PECO	184		—		192		192		184		—		201		201
SNF Obligation
Exelon	$	1,206	$	999	$	—	$	999	$	1,199	$	1,055	$	—	$	1,055
Generation	1,206		999		—		999		1,199		1,055		—		1,055

____

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

105

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

Recurring Fair Value Measurements

The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2020 and December 31, 2019:

Exelon and Generation

	Exelon														Generation
As of June 30, 2020	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Assets
Cash equivalents(a)	$	1,864		$	—		$	—		$	—	$	1,864		$	162		$	—		$	—		$	—	$	162
NDT fund investments
Cash equivalents(b)	345			78			—			—		423			345			78			—			—		423
Equities	3,080			1,599			—			1,280		5,959			3,080			1,599			—			1,280		5,959
Fixed income
Corporate debt	—			1,501			270			—		1,771			—			1,501			270			—		1,771
U.S. Treasury and agencies	1,864			116			—			—		1,980			1,864			116			—			—		1,980
Foreign governments	—			42			—			—		42			—			42			—			—		42
State and municipal debt	—			94			—			—		94			—			94			—			—		94
Other	—			29			—			965		994			—			29			—			965		994
Fixed income subtotal	1,864			1,782			270			965		4,881			1,864			1,782			270			965		4,881
Private credit	—			—			229			510		739			—			—			229			510		739
Private equity	—			—			—			423		423			—			—			—			423		423
Real estate	—			—			—			647		647			—			—			—			647		647
NDT fund investments subtotal(c)(d)	5,289			3,459			499			3,825		13,072			5,289			3,459			499			3,825		13,072
Rabbi trust investments
Cash equivalents	50			—			—			—		50			4			—			—			—		4
Mutual funds	79			—			—			—		79			25			—			—			—		25
Fixed income	—			10			—			—		10			—			—			—			—		—
Life insurance contracts	—			77			43			—		120			—			24			—			—		24
Rabbi trust investments subtotal	129			87			43			—		259			29			24			—			—		53
Commodity derivative assets
Economic hedges	770			2,382			1,670			—		4,822			770			2,382			1,670			—		4,822
Proprietary trading	—			47			43			—		90			—			47			43			—		90
Effect of netting and allocation of collateral(e)(f)	(849		)	(2,124		)	(903		)	—		(3,876		)	(849		)	(2,124		)	(903		)	—		(3,876		)
Commodity derivative assets subtotal	(79		)	305			810			—		1,036			(79		)	305			810			—		1,036
DPP consideration	—			635			—			—		635			—			635			—			—		635
Total assets	7,203			4,486			1,352			3,825		16,866			5,401			4,423			1,309			3,825		14,958

106

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

	Exelon														Generation
As of June 30, 2020	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Liabilities
Commodity derivative liabilities
Economic hedges	(933		)	(2,541		)	(1,529		)	—		(5,003		)	(933		)	(2,541		)	(1,211		)	—		(4,685		)
Proprietary trading	—			(44		)	(16		)	—		(60		)	—			(44		)	(16		)	—		(60		)
Effect of netting and allocation of collateral(e)(f)	933			2,443			1,076			—		4,452			933			2,443			1,076			—		4,452
Commodity derivative liabilities subtotal	—			(142		)	(469		)	—		(611		)	—			(142		)	(151		)	—		(293		)
Deferred compensation obligation	—			(127		)	—			—		(127		)	—			(35		)	—			—		(35		)
Total liabilities	—			(269		)	(469		)	—		(738		)	—			(177		)	(151		)	—		(328		)
Total net assets	$	7,203		$	4,217		$	883		$	3,825	$	16,128		$	5,401		$	4,246		$	1,158		$	3,825	$	14,630

107

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

	Exelon														Generation
As of December 31, 2019	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Assets
Cash equivalents(a)	$	639		$	—		$	—		$	—	$	639		$	214		$	—		$	—		$	—	$	214
NDT fund investments
Cash equivalents(b)	365			87			—			—		452			365			87			—			—		452
Equities	3,353			1,753			—			1,388		6,494			3,353			1,753			—			1,388		6,494
Fixed income
Corporate debt	—			1,469			257			—		1,726			—			1,469			257			—		1,726
U.S. Treasury and agencies	1,808			131			—			—		1,939			1,808			131			—			—		1,939
Foreign governments	—			42			—			—		42			—			42			—			—		42
State and municipal debt	—			90			—			—		90			—			90			—			—		90
Other	—			33			—			953		986			—			33			—			953		986
Fixed income subtotal	1,808			1,765			257			953		4,783			1,808			1,765			257			953		4,783
Private credit	—			—			254			508		762			—			—			254			508		762
Private equity	—			—			—			402		402			—			—			—			402		402
Real estate	—			—			—			607		607			—			—			—			607		607
NDT fund investments subtotal(c)(d)	5,526			3,605			511			3,858		13,500			5,526			3,605			511			3,858		13,500
Rabbi trust investments
Cash equivalents	50			—			—			—		50			4			—			—			—		4
Mutual funds	81			—			—			—		81			25			—			—			—		25
Fixed income	—			12			—			—		12			—			—			—			—		—
Life insurance contracts	—			78			41			—		119			—			25			—			—		25
Rabbi trust investments subtotal	131			90			41			—		262			29			25			—			—		54
Commodity derivative assets
Economic hedges	768			2,491			1,485			—		4,744			768			2,491			1,485			—		4,744
Proprietary trading	—			37			60			—		97			—			37			60			—		97
Effect of netting and allocation of collateral(e)(f)	(908		)	(2,162		)	(588		)	—		(3,658		)	(908		)	(2,162		)	(588		)	—		(3,658		)
Commodity derivative assets subtotal	(140		)	366			957			—		1,183			(140		)	366			957			—		1,183
Total assets	6,156			4,061			1,509			3,858		15,584			5,629			3,996			1,468			3,858		14,951

108

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

	Exelon														Generation
As of December 31, 2019	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Liabilities
Commodity derivative liabilities
Economic hedges	(1,071		)	(2,855		)	(1,228		)	—		(5,154		)	(1,071		)	(2,855		)	(927		)	—		(4,853		)
Proprietary trading	—			(34		)	(15		)	—		(49		)	—			(34		)	(15		)	—		(49		)
Effect of netting and allocation of collateral(e)(f)	1,071			2,714			802			—		4,587			1,071			2,714			802			—		4,587
Commodity derivative liabilities subtotal	—			(175		)	(441		)	—		(616		)	—			(175		)	(140		)	—		(315		)
Deferred compensation obligation	—			(147		)	—			—		(147		)	—			(41		)	—			—		(41		)
Total liabilities	—			(322		)	(441		)	—		(763		)	—			(216		)	(140		)	—		(356		)
Total net assets	$	6,156		$	3,739		$	1,068		$	3,858	$	14,821		$	5,629		$	3,780		$	1,328		$	3,858	$	14,595

_________

(a) Exelon excludes cash of $684 million and $373 million at June 30, 2020 and December 31, 2019, respectively, and restricted cash of $132 million and $110 million at June 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $178 million and $177 million at June 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $401 million and $177 million at June 30, 2020 and December 31, 2019, respectively, and restricted cash of $73 million and $58 million at June 30, 2020 and December 31, 2019, respectively. 

(b) Includes $101 million and $90 million of cash received from outstanding repurchase agreements at June 30, 2020 and December 31, 2019, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c) Includes derivative assets of less than $1 million and $2 million, which have total notional amounts of $769 million and $724 million at June 30, 2020 and December 31, 2019, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of Exelon and Generation's exposure to credit or market loss.

(d) Excludes net liabilities of $155 million and $147 million at June 30, 2020 and December 31, 2019, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.

(e) Collateral posted/(received) from counterparties totaled $84 million, $319 million and $173 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, 2020. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $163 million, $551 million and $214 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2019.

(f) Of the collateral posted/(received), $383 million and $511 million represents variation margin on the exchanges as of June 30, 2020 and December 31, 2019, respectively.

As of June 30, 2020, Exelon and Generation have outstanding commitments to invest in fixed income, private credit, private equity and real estate investments of approximately $58 million, $147 million, $316 million, and $410 million, respectively. These commitments will be funded by Generation’s existing NDT funds.

Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $76 million and $66 million as of June 30, 2020, respectively. Changes in fair value, cumulative adjustments and impairments were not material for the three and six months ended June 30, 2020.

109

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

ComEd, PECO and BGE

	ComEd											PECO										BGE
As of June 30, 2020	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents(a)	$	578	$	—		$	—		$	578		$	353	$	—		$	—	$	353		$	188	$	—		$	—	$	188
Rabbi trust investments
Mutual funds	—		—			—			—			8		—			—		8			10		—			—		10
Life insurance contracts	—		—			—			—			—		11			—		11			—		—			1		1
Rabbi trust investments subtotal	—		—			—			—			8		11			—		19			10		—			1		11
Total assets	578		—			—			578			361		11			—		372			198		—			1		199
Liabilities
Deferred compensation obligation	—		(6		)	—			(6		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities(b)	—		—			(318		)	(318		)	—		—			—		—			—		—			—		—
Total liabilities	—		(6		)	(318		)	(324		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	578	$	(6	)	$	(318	)	$	254		$	361	$	3		$	—	$	364		$	198	$	(5	)	$	1	$	194

	ComEd											PECO										BGE
As of December 31, 2019	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents(a)	$	280	$	—		$	—		$	280		$	15	$	—		$	—	$	15		$	—	$	—		$	—	$	—
Rabbi trust investments
Mutual funds	—		—			—			—			8		—			—		8			8		—			—		8
Life insurance contracts	—		—			—			—			—		11			—		11			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			8		11			—		19			8		—			—		8
Total assets	280		—			—			280			23		11			—		34			8		—			—		8
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(9		)	—		(9		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities(b)	—		—			(301		)	(301		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(301		)	(309		)	—		(9		)	—		(9		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	280	$	(8	)	$	(301	)	$	(29	)	$	23	$	2		$	—	$	25		$	8	$	(5	)	$	—	$	3

_________

(a) ComEd excludes cash of $109 million and $90 million at June 30, 2020 and December 31, 2019, respectively, and restricted cash of $37 million and $33 million at June 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $166 million and $163 million at June 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  PECO excludes cash of $34 million and $12 million at June 30, 2020 and December 31, 2019, respectively.  BGE excludes cash of $7 million and $24 million at June 30, 2020 and December 31, 2019, respectively, and restricted cash of $1 million at both June 30, 2020 and December 31, 2019.

(b) The Level 3 balance consists of the current and noncurrent liability of $31 million and $287 million, respectively, at June 30, 2020, and $32 million and $269 million, respectively, at December 31, 2019, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

110

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL and ACE

	As of June 30, 2020										As of December 31, 2019
PHI	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents(a)	$	50	$	—		$	—	$	50		$	124	$	—		$	—	$	124
Rabbi trust investments
Cash equivalents	44		—			—		44			44		—			—		44
Mutual funds	13		—			—		13			14		—			—		14
Fixed income	—		10			—		10			—		12			—		12
Life insurance contracts	—		24			43		67			—		24			41		65
Rabbi trust investments subtotal	57		34			43		134			58		36			41		135
Total assets	107		34			43		184			182		36			41		259
Liabilities
Deferred compensation obligation	—		(16		)	—		(16		)	—		(19		)	—		(19		)
Total liabilities	—		(16		)	—		(16		)	—		(19		)	—		(19		)
Total net assets	$	107	$	18		$	43	$	168		$	182	$	17		$	41	$	240

	Pepco										DPL								ACE
As of June 30, 2020	Level 1		Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	34	$	—		$	—	$	34		$	—	$	—	$	—	$	—	$	14	$	—	$	—	$	14
Rabbi trust investments
Cash equivalents	43		—			—		43			—		—		—		—		—		—		—		—
Fixed income	—		2			—		2			—		—		—		—		—		—		—		—
Life insurance contracts	—		24			42		66			—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	43		26			42		111			—		—		—		—		—		—		—		—
Total assets	77		26			42		145			—		—		—		—		14		—		—		14
Liabilities
Deferred compensation obligation	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total liabilities	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total net assets	$	77	$	24		$	42	$	143		$	—	$	—	$	—	$	—	$	14	$	—	$	—	$	14

111

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

	Pepco										DPL								ACE
As of December 31, 2019	Level 1		Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	34	$	—		$	—	$	34		$	—	$	—	$	—	$	—	$	16	$	—	$	—	$	16
Rabbi trust investments
Cash equivalents	43		—			—		43			—		—		—		—		—		—		—		—
Fixed income	—		2			—		2			—		—		—		—		—		—		—		—
Life insurance contracts	—		24			41		65			—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	43		26			41		110			—		—		—		—		—		—		—		—
Total assets	77		26			41		144			—		—		—		—		16		—		—		16
Liabilities
Deferred compensation obligation	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total liabilities	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total net assets (liabilities)	$	77	$	24		$	41	$	142		$	—	$	—	$	—	$	—	$	16	$	—	$	—	$	16

_________

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

112

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

Reconciliation of Level 3 Assets and Liabilities

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2020 and 2019:

	Exelon			Generation										ComEd				PHI and Pepco
Three Months Ended June 30, 2020	Total			NDT Fund Investments			Mark-to-Market Derivatives				Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts		Eliminated in Consolidation
Balance as of March 31, 2020	$	1,088		$	498		$	862			$	1,360		$	(314	)		$	42	$	—
Total realized / unrealized gains (losses)
Included in net income	(166		)	(1		)	(166		)	(a)	(167		)	—				1		—
Included in regulatory assets/liabilities	(4		)	—			—				—			(4		)	(b)	—		—
Change in collateral	(42		)	—			(42		)		(42		)	—				—		—
Purchases, sales, issuances and settlements
Purchases	30			3			27				30			—				—		—
Sales	(2		)	—			(2		)		(2		)	—				—		—
Settlements	(1		)	(1		)	—				(1		)	—				—		—
Transfers into Level 3	(9		)	—			(9		)	(c)	(9		)	—				—		—
Transfers out of Level 3	(11		)	—			(11		)	(c)	(11		)	—				—		—
Balance at June 30, 2020	$	883		$	499		$	659			$	1,158		$	(318	)		$	43	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2020	$	(72	)	$	(1	)	$	(72	)		$	(73	)	$	—			$	1	$	—

	Exelon			Generation										ComEd				PHI and Pepco
Six months ended June 30, 2020	Total			NDT Fund Investments			Mark-to-Market Derivatives				Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts		Eliminated in Consolidation
Balance as of December 31, 2019	$	1,068		$	511		$	817			$	1,328		$	(301	)		$	41	$	—
Total realized / unrealized gains (losses)
Included in net income	(156		)	(2		)	(156		)	(a)	(158		)	—				2		—
Included in noncurrent payables to affiliates	—			(1		)	—				(1		)	—				—		1
Included in regulatory assets	(18		)	—			—				—			(17		)	(b)	—		(1		)
Change in collateral	(41		)	—			(41		)		(41		)	—				—		—
Purchases, sales, issuances and settlements
Purchases	71			6			65				71			—				—		—
Sales	(24		)	—			(24		)		(24		)	—				—		—
Settlements	(15		)	(15		)	—				(15		)	—				—		—
Transfers into Level 3	(6		)	—			(6		)	(c)	(6		)	—				—		—
Transfers out of Level 3	4			—			4			(c)	4			—				—		—
Balance as of June 30, 2020	$	883		$	499		$	659			$	1,158		$	(318	)		$	43	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2020	$	115		$	(2	)	$	115			$	113		$	—			$	2	$	—

113

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

	Exelon			Generation										ComEd				PHI and Pepco
Three Months Ended June 30, 2019	Total			NDT Fund Investments			Mark-to-Market Derivatives				Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts		Eliminated in Consolidation
Balance as of March 31, 2019	$	838		$	540		$	499			$	1,039		$	(240	)		$	39	$	—
Total realized / unrealized gains (losses)
Included in net income	275			2			272			(a)	274			—				1		—
Included in noncurrent payables to affiliates	—			10			—				10			—				—		(10		)
Included in regulatory assets	(23		)	—			—				—			(33		)	(b)	—		10
Change in collateral	106			—			106				106			—				—		—
Purchases, sales, issuances and settlements
Purchases	51			40			11				51			—				—		—
Sales	(1		)	—			(1		)		(1		)	—				—		—
Settlements	(53		)	(53		)	—				(53		)	—				—		—
Transfers into Level 3	3			—			3			(c)	3			—				—		—
Transfers out of Level 3	(17		)	—			(17		)	(c)	(17		)	—				—		—
Balance as of June 30, 2019	$	1,179		$	539		$	873			$	1,412		$	(273	)		$	40	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2019	$	339		$	1		$	337			$	338		$	—			$	1	$	—

	Exelon			Generation										ComEd				PHI and Pepco
Six Months Ended June 30, 2019	Total			NDT Fund Investments			Mark-to-Market Derivatives				Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts		Eliminated in Consolidation
Balance as of December 31, 2018	$	907		$	543		$	575			$	1,118		$	(249	)		$	38	$	—
Total realized / unrealized gains (losses)
Included in net income	46			3			41			(a)	44			—				2		—
Included in noncurrent payables to affiliates	—			21			—				21			—				—		(21		)
Included in regulatory assets	(3		)	—			—				—			(24		)	(b)	—		21
Change in collateral	187			—			187				187			—				—		—
Purchases, sales, issuances and settlements
Purchases	110			42			68				110			—				—		—
Sales	(1		)	—			(1		)		(1		)	—				—		—
Settlements	(70		)	(70		)	—				(70		)	—				—		—
Transfers into Level 3	3			—			3			(c)	3			—				—		—
Transfers out of Level 3	—			—			—			(c)	—			—				—		—
Balance as of June 30, 2019	$	1,179		$	539		$	873			$	1,412		$	(273	)		$	40	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2019	$	191		$	3		$	186			$	189		$	—			$	2	$	—

114

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

__________

(a) Includes a reduction for the reclassification of $94 million and $271 million of realized losses due to the settlement of derivative contracts for the three and six months ended June 30, 2020. Includes a reduction for the reclassification of $65 million and $145 million of realized losses due to the settlement of derivative contracts for the three and six months ended June 30, 2019.

(b) Includes $12 million of decreases in fair value and an increase for realized losses due to settlements of $8 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2020. Includes $35 million of decreases in fair value and an increase for realized losses due to settlements of $18 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2020. Includes $41 million of decreases in fair value and an increase for realized losses due to settlements of $8 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2019. Includes $37 million of decreases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2019.

(c) Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2020 and 2019:

	Exelon											Generation									PHI and Pepco
	Operating Revenues			Purchased Power and Fuel			Operating and Maintenance		Other, net			Operating Revenues			Purchased Power and Fuel			Other, net			Operating and Maintenance
Total realized (losses) gains for the three months ended June 30, 2020	$	(137	)	$	(29	)	$	1	$	—		$	(137	)	$	(29	)	$	—		$	1
Total realized (losses) gains for the six months ended June 30, 2020	(65		)	(91		)	2		—			(65		)	(91		)	—			2
Total unrealized (losses) gains for the three months ended June 30, 2020	(39		)	(33		)	1		(1		)	(39		)	(33		)	(1		)	1
Total unrealized gains (losses) for the six months ended June 30, 2020	166			(51		)	2		(2		)	166			(51		)	(2		)	2

	Exelon									Generation							PHI and Pepco
	Operating Revenues		Purchased Power and Fuel			Operating and Maintenance		Other, net		Operating Revenues		Purchased Power and Fuel			Other, net		Operating and Maintenance
Total realized gains (losses) for the three months ended June 30, 2019	$	275	$	(3	)	$	1	$	2	$	275	$	(3	)	$	2	$	1
Total realized gains (losses) for the six months ended June 30, 2019	147		(106		)	2		3		147		(106		)	3		2
Total unrealized gains (losses) for the three months ended June 30, 2019	360		(23		)	1		1		360		(23		)	1		1
Total unrealized gains (losses) gains for the six months ended June 30, 2019	269		(83		)	2		3		269		(83		)	3		2

115

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

Valuation Techniques Used to Determine Fair Value

Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of the Exelon 2019 Form 10-K.

Valuation Techniques Used to Determine Net asset Value (Exelon and Generation)

Certain NDT Fund Investments are not classified within the fair value hierarchy and are included under the heading “Not subject to leveling” in the table above. These investments are measured at fair value using NAV per share as a practical expedient and include commingled funds, mutual funds which are not publicly quoted, managed private credit funds, private equity and real estate funds.

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

Deferred Purchase Price Consideration (Exelon and Generation)

Exelon and Generation have DPP consideration for the sale of certain receivables of retail electricity at Generation. This amount is valued based on the sales price of the receivables net of allowance for credit losses based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. Since the DPP consideration is based on the sales price of the receivables, it is categorized as Level 2 in the fair value hierarchy. See Note 5 - Accounts Receivable for additional information on the sale of certain receivables.

116

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

Mark-to-Market Derivatives (Exelon, Generation and ComEd)

The table below discloses the significant inputs to the forward curve used to value mark-to-market derivatives.

Type of trade	Fair Value at June 30, 2020			Fair Value at December 31, 2019			Valuation Technique	Unobservable Input	2020 Range & Arithmetic Average				2019 Range & Arithmetic Average
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)	$	459		$	558		Discounted Cash Flow	Forward power price	$7	-	$148	$28	$9	-	$180	$29
								Forward gas price	$1.45	-	$7.66	$2.58	$0.83	-	$10.72	$2.55
							Option Model	Volatility percentage	9%	-	522%	92%	8%	-	236%	70%
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)	$	27		$	45		Discounted Cash Flow	Forward power price	$13	-	$148	$32	$25	-	$180	$33
Mark-to-market derivatives (Exelon and ComEd)	$	(318	)	$	(301	)	Discounted Cash Flow	Forward heat rate(c)	8x	-	9x	8.85x	9x	-	10x	9.68x
								Marketability reserve	4%	-	8%	5.24%	3%	-	7%	4.95%
								Renewable factor	93%	-	122%	100%	91%	-	123%	99%

_________

(a) The valuation techniques, unobservable inputs, ranges and arithmetic averages are the same for the asset and liability positions.

(b) The fair values do not include cash collateral posted on level three positions of $173 million and $214 million as of June 30, 2020 and December 31, 2019, respectively.

(c) Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

14. Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 18 of the Exelon 2019 Form 10-K.

Commitments

PHI Merger Commitments (Exelon, PHI, Pepco, DPL and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain

117

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

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

Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments(a)	91		72		60		7		5

_________

(a) Remaining commitments extend through 2026 and include rate credits, energy efficiency programs and delivery system modernization.

In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia, and Delaware at an estimated cost of approximately $127 million, which will generate future earnings at Exelon and Generation. Investment costs, which are expected to be primarily capital in nature, are recognized as incurred and recorded in Exelon's and Generation's financial statements. As of June 30, 2020, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $123 million. Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the DPSC in 2019. The third and final 40 MW wind REC tranche will be conducted in 2022.

118

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

Commercial Commitments (All Registrants). The Registrants’ commercial commitments as of June 30, 2020, representing commitments potentially triggered by future events were as follows:

			Expiration within
	Total		2020		2021		2022		2023		2024		2025 and beyond
Exelon
Letters of credit	$	1,291	$	475	$	816	$	—	$	—	$	—	$	—
Surety bonds(a)	902		550		335		17		—		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values(b)	28		1		2		4		3		7		11
Total commercial commitments	$	2,599	$	1,026	$	1,153	$	21	$	3	$	7	$	389
Generation
Letters of credit	$	1,276	$	467	$	809	$	—	$	—	$	—	$	—
Surety bonds(a)	754		479		258		17		—		—		—
Total commercial commitments	$	2,030	$	946	$	1,067	$	17	$	—	$	—	$	—
ComEd
Letters of credit	$	7	$	4	$	3	$	—	$	—	$	—	$	—
Surety bonds(a)	15		8		7		—		—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	222	$	12	$	10	$	—	$	—	$	—	$	200
PECO
Surety bonds(a)	$	6	$	4	$	2	$	—	$	—	$	—	$	—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	184	$	4	$	2	$	—	$	—	$	—	$	178
BGE
Letters of credit	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds(a)	3		2		1		—		—		—		—
Total commercial commitments	$	5	$	4	$	1	$	—	$	—	$	—	$	—
PHI
Surety bonds(a)	$	22	$	6	$	16	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	28		1		2		4		3		7		11
Total commercial commitments	$	50	$	7	$	18	$	4	$	3	$	7	$	11
Pepco
Surety bonds(a)	$	14	$	1	$	13	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	9		—		1		1		1		2		4
Total commercial commitments	$	23	$	1	$	14	$	1	$	1	$	2	$	4
DPL
Surety bonds(a)	$	4	$	3	$	1	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	12		—		1		2		1		4		4
Total commercial commitments	$	16	$	3	$	2	$	2	$	1	$	4	$	4
ACE
Surety bonds(a)	$	4	$	2	$	2	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	7		1		—		1		1		1		3
Total commercial commitments	$	11	$	3	$	2	$	1	$	1	$	1	$	3

_________

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

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

Note 14 — Commitments and Contingencies

(b) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $74 million guaranteed by Exelon and PHI, of which $25 million, $31 million and $18 million is guaranteed by Pepco, DPL and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Environmental Remediation Matters

General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.

MGP Sites (Exelon and the Utility Registrants). ComEd, PECO, BGE and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

• ComEd has 21 sites that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2025.

• PECO has 8 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.

• BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2021.

• DPL has 1 site that is currently under study and the required cost at the site is not expected to be material.

The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.

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

Note 14 — Commitments and Contingencies

As of June 30, 2020 and December 31, 2019, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:

	June 30, 2020				December 31, 2019
	Total environmental investigation and remediation liabilities		Portion of total related to MGP investigation and remediation		Total environmental investigation and remediation liabilities		Portion of total related to MGP investigation and remediation
Exelon	$	463	$	309	$	478	$	320
Generation	103		—		105		—
ComEd	293		292		304		303
PECO	19		17		19		17
BGE	2		—		2		—
PHI	46		—		48		—
Pepco	44		—		46		—
DPL	1		—		1		—
ACE	1		—		1		—

Cotter Corporation (Exelon and Generation). The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.

In September 2018, the EPA issued its Record of Decision (ROD) Amendment for the selection of a final remedy. The ROD Amendment modified the remedy previously selected by EPA in its 2008 ROD. While the ROD required only that the radiological materials and other wastes at the site be capped, the ROD Amendment requires partial excavation of the radiological materials in addition to the previously selected capping remedy. The ROD Amendment also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed by early 2022. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Cotter (Generation’s indemnitee) provided a non-binding good faith offer to conduct, or finance, a portion of the remedy, subject to certain conditions. The total estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred collectively by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.

One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial statements.

In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation (RI)/Feasibility Study (FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $20 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future financial statements.

In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s (now Generation's) indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 28, 2021 so that settlement discussions can proceed. On August 3, 2020, the DOJ advised Cotter and the other PRPs that it is seeking approximately $90 million from all the PRPs and that the PRPs must submit a good faith joint proposed settlement offer by December 1, 2020. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above.

Benning Road Site (Exelon, Generation, PHI and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility, which was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River.

Since 2013, Pepco and Pepco Energy Services (now Generation, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have submitted multiple draft RI reports to the DOEE. In September 2019, Pepco and Generation issued a draft “final” RI report which DOEE approved and on October 4, 2019 released this document for review and comment by the public. The 45-day comment period ended on November 18, 2019 and a public meeting was held by Pepco on November 2, 2019. Pepco and Generation will proceed to develop a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the FS, and approval by the DOEE, by September 16, 2021.

DOEE will then prepare a Proposed Plan and issue a Record of Decision identifying any further response actions determined to be necessary, after considering public comment on the Proposed Plan. PHI, Pepco and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.

Anacostia River Tidal Reach (Exelon, PHI and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and the National Park Service have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a "Consultative Working Group" to provide input into the process for future remedial actions and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road site RI/FS. In addition, the

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

District of Columbia Council directed DOEE to form an official advisory committee made up of members of federal, state and local environmental regulators, community and environmental groups and various academic and technical experts to provide guidance and support to DOEE as the project progressed. This group, called the Anacostia Leadership Council, has met regularly since it was formed. Pepco has participated in the Consultative Working Group. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing.

Pepco has determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best estimate of its share of those costs based on DOEE’s stated position following a series of meetings attended by representatives from the Anacostia Leadership Council and the Consultative Working Group. On December 27, 2019, DOEE released for review and comment by the public a Focused Feasibility Study (FFS) and a Proposed Plan (PP). The FFS and PP will be the basis for the Interim ROD, which is expected to be completed in September 2020. The FFS and PP are consistent with the DOEE’s stated position to follow an adaptive management approach which will allow several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion. Pepco concluded that incremental exposure remains reasonably possible, however management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.

In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. The Natural Resource Damages (NRD) assessment typically takes place following cleanup because cleanups sometimes also effectively restore affected natural resources. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the range of loss.

Litigation and Regulatory Matters

Asbestos Personal Injury Claims (Exelon and Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.

At June 30, 2020 and December 31, 2019, Exelon and Generation had recorded estimated liabilities of approximately $92 million and $83 million, respectively, in total for asbestos-related bodily injury claims. As of June 30, 2020, approximately $26 million of this amount related to 268 open claims presented to Generation, while the remaining $66 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.

It is reasonably possible that additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued could have a material, unfavorable impact on Exelon’s and Generation’s financial statements. However, management cannot reasonably estimate a range of loss beyond the amounts recorded.

City of Everett Tax Increment Financing Agreement (Exelon and Generation). On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. On January 8, 2020, the Massachusetts Superior Court affirmed the decision of the EACC denying the City's petition. The City had until March 9, 2020 to appeal the decision and did not. As a result, the decision is final and the case is resolved. It is reasonably possible that property taxes assessed in future periods, including those following the expiration of the TIF Agreement on June 30, 2020, could be material to Generation’s financial statements.

Subpoenas (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the United States Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date. The payments were recorded within Operating and maintenance expense in Exelon’s and ComEd’s Consolidated Statements of Operations and Comprehensive Income in the second quarter of 2020. The payments will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon.

Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ends with no charges being brought against Exelon.

The SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to the SEC investigation, as this contingency is neither probable nor reasonably estimable at this time. Management is currently unable to estimate a range of reasonably possible loss as this matter is subject to change.

Subsequent to Exelon announcing the receipt of the subpoenas, a putative class action lawsuit was filed against Exelon and certain officers of Exelon and ComEd alleging misrepresentations or omissions purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. In addition, a derivative shareholder lawsuit was filed against Exelon, its directors and certain officers of Exelon and ComEd alleging, among other things, breaches of fiduciary duties also purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. On July 28, 2020, plaintiff voluntarily dismissed this derivative action without prejudice to refile. Two additional putative class actions have been filed on July 27 and July 28, 2020. The first putative class action lawsuit against ComEd and Exelon has been filed in Illinois state court and seeks restitution and compensatory damages on behalf of ComEd customers. The second putative class action lawsuit against ComEd has been filed in federal court and alleges civil violations of federal racketeering laws. On August 2, 2020, plaintiffs in the federal lawsuit requested that ComEd waive service, which would make ComEd’s response due in October 2020. Both putative class action lawsuits relate to the conduct alleged in the DPA. No loss contingencies have been reflected in Exelon’s and ComEd’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time. Management is currently unable to estimate a range of reasonably possible loss due to the early stages of the lawsuits.

General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

(3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

15. Changes in Accumulated Other Comprehensive Income (Exelon)

The following tables present changes in Exelon's AOCI, net of tax, by component:

Three Months Ended June 30, 2020	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items (a)			Foreign Currency Items			Total
Beginning balance	$	(3	)	$	(3,135	)	$	(35	)	$	(3,173	)
OCI before reclassifications	—			2			2			4
Amounts reclassified from AOCI	—			37			—			37
Net current-period OCI	—			39			2			41
Ending balance	$	(3	)	$	(3,096	)	$	(33	)	$	(3,132	)

Three Months Ended June 30, 2019	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items (a)			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates (b)			Total
Beginning balance	$	(2	)	$	(2,978	)	$	(31	)	$	(1	)	$	(3,012	)
OCI before reclassifications	—			(1		)	2			(1		)	—
Amounts reclassified from AOCI	—			22			—			—			22
Net current-period OCI	—			21			2			(1		)	22
Ending balance	$	(2	)	$	(2,957	)	$	(29	)	$	(2	)	$	(2,990	)

Six Months Ended June 30, 2020	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items (a)			Foreign Currency Items			Total
Beginning balance	$	(2	)	$	(3,165	)	$	(27	)	$	(3,194	)
OCI before reclassifications	(1		)	(5		)	(6		)	(12		)
Amounts reclassified from AOCI	—			74			—			74
Net current-period OCI	(1		)	69			(6		)	62
Ending balance	$	(3	)	$	(3,096	)	$	(33	)	$	(3,132	)

Six Months Ended June 30, 2019	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items (a)			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates (b)			Total
Beginning balance	$	(2	)	$	(2,960	)	$	(33	)	$	—		$	(2,995	)
OCI before reclassifications	—			(39		)	4			(2		)	(37		)
Amounts reclassified from AOCI	—			42			—			—			42
Net current-period OCI	—			3			4			(2		)	5
Ending balance	$	(2	)	$	(2,957	)	$	(29	)	$	(2	)	$	(2,990	)

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Changes in Accumulated Other Comprehensive Income

_________

(a) AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 10 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

(b) All amounts are net of noncontrolling interests.

The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):

	Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	4		$	6		$	8		$	12
Actuarial loss reclassified to periodic benefit cost	(17		)	(13		)	(34		)	(26		)
Pension and non-pension postretirement benefit plans valuation adjustment	—			—			3			14

16. Variable Interest Entities (Exelon, Generation, PHI and ACE)

At June 30, 2020 and December 31, 2019, Exelon, Generation, PHI and ACE collectively consolidated several VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.

Consolidated VIEs

The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements of Exelon, Generation, PHI and ACE as of June 30, 2020 and December 31, 2019. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnote to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI and ACE.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 16 — Variable Interest Entities

	June 30, 2020								December 31, 2019
	Exelon		Generation		PHI (a)		ACE		Exelon		Generation		PHI (a)		ACE
Cash and cash equivalents	$	114	$	114	$	—	$	—	$	163	$	163	$	—	$	—
Restricted cash and cash equivalents	105		102		3		3		88		85		3		3
Accounts receivable
Customer	145		145		—		—		151		151		—		—
Other	38		38		—		—		39		39		—		—
Unamortized energy contract assets (b)	22		22		—		—		23		23		—		—
Inventories, net
Materials and supplies	236		236		—		—		227		227		—		—
Other current assets	675		671		4		—		32		31		1		—
Total current assets	1,335		1,328		7		3		723		719		4		3
Property, plant and equipment, net (c)	5,939		5,939		—		—		6,022		6,022		—		—
Nuclear decommissioning trust funds	2,642		2,642		—		—		2,741		2,741		—		—
Unamortized energy contract assets (b)	258		258		—		—		250		250		—		—
Other noncurrent assets	44		30		14		11		89		73		16		14
Total noncurrent assets	8,883		8,869		14		11		9,102		9,086		16		14
Total assets	$	10,218	$	10,197	$	21	$	14	$	9,825	$	9,805	$	20	$	17
Long-term debt due within one year	$	191	$	167	$	24	$	20	$	544	$	523	$	21	$	20
Accounts payable	71		71		—		—		106		106		—		—
Accrued expenses	60		60		—		—		70		70		—		—
Unamortized energy contract liabilities	6		6		—		—		8		8		—		—
Other current liabilities	6		6		—		—		3		3		—		—
Total current liabilities	334		310		24		20		731		710		21		20
Long-term debt	947		934		13		11		527		504		23		21
Asset retirement obligations (d)	2,182		2,182		—		—		2,128		2,128		—		—
Unamortized energy contract liabilities	1		1		—		—		1		1		—		—
Other noncurrent liabilities	80		80		—		—		89		89		—		—
Total noncurrent liabilities	3,210		3,197		13		11		2,745		2,722		23		21
Total liabilities	$	3,544	$	3,507	$	37	$	31	$	3,476	$	3,432	$	44	$	41

_________

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

(b) These are unrestricted assets to Exelon and Generation.

(c) Exelon’s and Generation’s balances include unrestricted assets of $1 million and $20 million as of June 30, 2020 and December 31, 2019.

(d) Exelon’s and Generation’s balances include liabilities with recourse of $2 million and $3 million as of June 30, 2020 and December 31, 2019, respectively.

127

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 16 — Variable Interest Entities

As of June 30, 2020 and December 31, 2019, Exelon's and Generation's consolidated VIEs consist of:

Consolidated VIE or VIE groups:	Reason entity is a VIE:	Reason Generation is primary beneficiary:
CENG - A joint venture between Generation and EDF. Generation has a 50.01% equity ownership in CENG. See additional discussion below.	Disproportionate relationship between equity interest and operational control as a result of NOSA described further below.	Generation conducts the operational activities.
EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. See additional discussion below.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation conducts the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by EGRP. Generation is a minority interest holder.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation conducts the operational activities.
Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&E through a PPA.	The PPA contract absorbs variability through a performance guarantee.	Generation conducts all activities.
Equity investment in distributed energy company - Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE (see Unconsolidated VIEs disclosure below). Generation fully impaired this investment in the third quarter of 2019. See Note 11— Asset Impairments of the Exelon 2019 Form 10-K for additional information.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation conducts the operational activities.
NER - A bankruptcy remote, special purpose entity which is 100% owned by Generation, which purchases certain of Generation’s customer accounts receivable arising from the sale of retail electricity. NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. See Note 5 - Accounts Receivable for additional information on the sale of receivables.	Equity capitalization is insufficient to support its operations.	Generation conducts all activities.

CENG - On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the NOSA pursuant to which Generation conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF.

EDF has the option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, Generation received notice of EDF's intention to exercise the put option to sell its interest in CENG to Generation and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period.

At this time, Generation cannot reasonably predict the ultimate purchase price that will be paid to EDF for its interest in CENG. The transaction will require approval by the NYPSC and the FERC. The process and regulatory approvals could take one to two years or more to complete.

See Note 2 - Mergers, Acquisitions and Dispositions of the Exelon 2019 Form 10-K for additional information regarding the Put Option Agreement with EDF.

Exelon and Generation, where indicated, provide the following support to CENG:

• Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. See Note 18 — Commitments and Contingencies of the Exelon 2019 Form 10-K for more details,

128

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 16 — Variable Interest Entities

• Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and

• Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.

EGRP - EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance and there is limited recourse related to Generation related to certain solar and wind entities.

In 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 12— Debt and Credit Agreements for additional information on ExGen Renewables IV.

As of June 30, 2020 and December 31, 2019, Exelon's, PHI's and ACE's consolidated VIE consists of:

Consolidated VIEs:	Reason entity is a VIE:	Reason ACE is the primary beneficiary:
ACE Funding - A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. Proceeds from the sale of each series of Transition Bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees.	ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ATF. The bondholders also have a variable interest for the investment made to purchase the Transition Bonds.	ACE controls the servicing activities.

Unconsolidated VIEs

Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements.

As of June 30, 2020 and December 31, 2019, Exelon and Generation had significant unconsolidated variable interests in several VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.

129

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 16 — Variable Interest Entities

The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities:

	June 30, 2020						December 31, 2019
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	705	$	417	$	1,122	$	636	$	443	$	1,079
Total liabilities(a)	172		227		399		33		227		260
Exelon's ownership interest in VIE(a)	—		168		168		—		191		191
Other ownership interests in VIE(a)	533		22		555		604		25		629

_________

(a) These items represent amounts on the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. Exelon and Generation do not have any exposure to loss as they do not have a carrying amount in the equity investment VIEs as of June 30, 2020 and December 31, 2019.

As of June 30, 2020 and December 31, 2019, Exelon's and Generation's unconsolidated VIEs consist of:

Unconsolidated VIE groups:	Reason entity is a VIE:	Reason Generation is not the primary beneficiary:
Equity investments in distributed energy companies - 1) Generation has a 90% equity ownership in a distributed energy company. 2) Generation, via a consolidated VIE, has a 90% equity ownership in another distributed energy company (See Consolidated VIEs disclosure above). Generation fully impaired this investment in the third quarter of 2019. See Note 11— Asset Impairments of the Exelon 2019 Form 10-K for additional information.	Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation does not conduct the operational activities.
Energy Purchase and Sale agreements - Generation has several energy purchase and sale agreements with generating facilities.	PPA contracts that absorb variability through fixed pricing.	Generation does not conduct the operational activities.

130

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

17. Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

	Operating revenues
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended June 30, 2020
Operating lease income	$	14	$	12	$	—	$	—	$	—	$	1	$	—	$	1	$	—
Variable lease income	80		79		—		—		—		1		—		1		—
Three Months Ended June 30, 2019
Operating lease income	$	14	$	12	$	—	$	—	$	—	$	1	$	—	$	1	$	—
Variable lease income	77		74		—		—		—		3		—		3		—
Six Months Ended June 30, 2020
Operating lease income	$	18	$	15	$	—	$	—	$	—	$	2	$	—	$	2	$	—
Variable lease income	149		148		—		—		—		1		—		1		—
Six Months Ended June 30, 2019
Operating lease income	$	18	$	15	$	—	$	—	$	—	$	2	$	—	$	2	$	—
Variable lease income	129		126		—		—		—		3		—		3		—

	Taxes other than income taxes
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended June 30, 2020
Utility taxes(a)	$	196	$	23	$	55	$	31	$	18	$	69	$	64	$	5	$	—
Property	149		64		8		4		40		33		21		11		1
Payroll	61		28		7		4		4		7		2		1		1
Three Months Ended June 30, 2019
Utility taxes(a)	$	209	$	32	$	55	$	30	$	21	$	71	$	67	$	4	$	—
Property	148		68		9		4		37		30		21		8		1
Payroll	61		30		7		4		4		7		2		1		1
Six Months Ended June 30, 2020
Utility taxes(a)	$	414	$	49	$	114	$	62	$	44	$	145	$	133	$	10	$	1
Property	297		133		15		8		79		62		41		20		1
Payroll	125		60		14		8		9		15		4		2		2
Six Months Ended June 30, 2019
Utility taxes(a)	$	432	$	58	$	118	$	63	$	48	$	145	$	136	$	9	$	—
Property	296		138		15		8		75		60		43		16		1
Payroll	127		64		14		7		8		14		3		2		2

_________

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

131

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

	Other, Net
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended June 30, 2020
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory agreement units	$	30		$	30		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	23			23			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units	645			645			—		—		—		—		—		—		—
Non-regulatory agreement units	452			452			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(542		)	(542		)	—		—		—		—		—		—		—
Decommissioning-related activities	608			608			—		—		—		—		—		—		—
AFUDC — Equity	26			—			8		4		6		8		6		1		1
Non-service net periodic benefit cost	14			—			—		—		—		—		—		—		—
Three Months Ended June 30, 2019
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory agreement units	$	77		$	77		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	230			230			—		—		—		—		—		—		—
Net unrealized (losses) gains on NDT funds
Regulatory agreement units	98			98			—		—		—		—		—		—		—
Non-regulatory agreement units	(98		)	(98		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(141		)	(141		)	—		—		—		—		—		—		—
Decommissioning-related activities	166			166			—		—		—		—		—		—		—
AFUDC — Equity	21			—			4		3		5		9		6		1		2
Non-service net periodic benefit cost	5			—			—		—		—		—		—		—		—

132

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

	Other, net
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Six Months Ended June 30, 2020
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory agreement units	$	77		$	77		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	104			104			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units	(287		)	(287		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(253		)	(253		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	167			167			—		—		—		—		—		—		—
Decommissioning-related activities	(192		)	(192		)	—		—		—		—		—		—		—
AFUDC — Equity	49			—			14		7		10		17		13		2		2
Non-service net periodic benefit cost	24			—			—		—		—		—		—		—		—
Six Months Ended June 30, 2019
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory agreement units	$	131		$	131		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	283			283			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units	476			476			—		—		—		—		—		—		—
Non-regulatory agreement units	182			182			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(487		)	(487		)	—		—		—		—		—		—		—
Decommissioning-related activities	585			585			—		—		—		—		—		—		—
AFUDC — Equity	43			—			9		6		10		18		12		2		4
Non-service net periodic benefit cost	10			—			—		—		—		—		—		—		—

_________

(a) Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.

(b) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

133

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

Supplemental Cash Flow Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.

	Depreciation, amortization and accretion
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Six Months Ended June 30, 2020
Property, plant and equipment(a)	$	1,715	$	577	$	458	$	159	$	195	$	289	$	126	$	76	$	69
Amortization of regulatory assets(a)	277		—		89		14		77		96		60		18		17
Amortization of intangible assets, net(a)	31		27		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(b)	12		10		—		—		—		—		—		—		—
Nuclear fuel(c)	459		459		—		—		—		—		—		—		—
ARO accretion(d)	247		247		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	2,741	$	1,320	$	547	$	173	$	272	$	385	$	186	$	94	$	86
Six Months Ended June 30, 2019
Property, plant and equipment(a)	$	1,859	$	789	$	439	$	149	$	173	$	266	$	117	$	71	$	57
Amortization of regulatory assets(a)	266		—		69		15		79		103		69		20		14
Amortization of intangible assets, net(a)	29		25		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(b)	5		5		—		—		—		—		—		—		—
Nuclear fuel(c)	513		513		—		—		—		—		—		—		—
ARO accretion(d)	250		248		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	2,922	$	1,580	$	508	$	164	$	252	$	369	$	186	$	91	$	71

_________

(a) Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

(b) Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

(c) Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

(d) Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

134

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

	Other non-cash operating activities
	Exelon			Generation			ComEd		PECO			BGE		PHI			Pepco			DPL			ACE
Six Months Ended June 30, 2020
Pension and non-pension postretirement benefit costs	$	203		$	58		$	57	$	3		$	31	$	35		$	7		$	4		$	7
Provision for uncollectible accounts	92			13			17		29			10		22			12			8			2
Other decommissioning-related activity(a)	(60		)	(60		)	—		—			—		—			—			—			—
Energy-related options(b)	27			27			—		—			—		—			—			—			—
True-up adjustments to decoupling mechanisms and formula rates(c)	55			—			13		(5		)	—		47			(2		)	24			25
Long-term incentive plan	(10		)	—			—		—			—		—			—			—			—
Amortization of operating ROU asset	112			80			1		—			15		14			3			4			2
Deferred Prosecution Agreement payments(d)	200			—			200		—			—		—			—			—			—
Six Months Ended June 30, 2019
Pension and non-pension postretirement benefit costs	$	212		$	62		$	47	$	5		$	29	$	48		$	12		$	8		$	8
Provision for uncollectible accounts	45			12			16		10			4		3			2			1			—
Other decommissioning-related activity(a)	(260		)	(261		)	—		—			—		—			—			—			—
Energy-related options(b)	43			43			—		—			—		—			—			—			—
True-up adjustments to decoupling mechanisms and formula rates(e)	14			—			24		—			—		(10		)	(8		)	(2		)	—
Long-term incentive plan	35			—			—		—			—		—			—			—			—
Amortization of operating ROU asset	115			78			1		—			15		17			4			5			2

_______

(a) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(c) For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency and transmission formula rates. For BGE, Pepco and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO and ACE, reflects the change in regulatory assets and liabilities associated with their transmission formula rates. See Note 2 — Regulatory Matters for additional information.

(d) See Note 14 — Commitments and Contingencies for additional information related to the Deferred Prosecution Agreement.

(e) For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution and energy efficiency formula rates. For Pepco and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms. See Note 2 — Regulatory Matters for additional information.

135

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.

	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2020
Cash and cash equivalents	$	2,129	$	483	$	403	$	380	$	195	$	39	$	19	$	6	$	8
Restricted cash	373		153		155		7		1		36		33		—		3
Restricted cash included in other long-term assets	178		—		166		—		—		11		—		—		11
Total cash, cash equivalents and restricted cash	$	2,680	$	636	$	724	$	387	$	196	$	86	$	52	$	6	$	22
December 31, 2019
Cash and cash equivalents	$	587	$	303	$	90	$	21	$	24	$	131	$	30	$	13	$	12
Restricted cash	358		146		150		6		1		36		33		—		2
Restricted cash included in other long-term assets	177		—		163		—		—		14		—		—		14
Total cash, cash equivalents and restricted cash	$	1,122	$	449	$	403	$	27	$	25	$	181	$	63	$	13	$	28
June 30, 2019
Cash and cash equivalents	$	735	$	575	$	65	$	20	$	8	$	54	$	18	$	3	$	4
Restricted cash	252		122		77		6		1		37		34		1		2
Restricted cash included in other long-term assets	191		—		174		—		—		17		—		—		17
Total cash, cash equivalents and restricted cash	$	1,178	$	697	$	316	$	26	$	9	$	108	$	52	$	4	$	23
December 31, 2018
Cash and cash equivalents	$	1,349	$	750	$	135	$	130	$	7	$	124	$	16	$	23	$	7
Restricted cash	247		153		29		5		6		43		37		1		4
Restricted cash included in other long-term assets	185		—		166		—		—		19		—		—		19
Total cash, cash equivalents and restricted cash	$	1,781	$	903	$	330	$	135	$	13	$	186	$	53	$	24	$	30

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

136

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

Supplemental Balance Sheet Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.

	Accrued expenses
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2020
Compensation-related accruals(a)	$	744	$	277	$	135	$	50	$	52	$	92	$	32	$	18	$	14
Taxes accrued	396		229		61		2		19		73		54		5		8
Interest accrued	357		53		119		37		46		51		25		8		13
December 31, 2019
Compensation-related accruals(a)	$	1,052	$	422	$	171	$	58	$	78	$	101	$	28	$	19	$	15
Taxes accrued	414		222		83		3		26		117		90		14		8
Interest accrued	337		65		110		37		46		49		23		8		12

_________

(a) Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

18. Related Party Transactions (All Registrants)

Operating revenues from affiliates

Generation

The following table presents Generation’s Operating revenues from affiliates, which are primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Operating revenues from affiliates:
ComEd(a)(b)	$	80	$	89	$	170	$	183
PECO(c)	41		35		78		80
BGE(d)	70		57		169		133
PHI	78		69		182		170
Pepco(e)	60		52		139		122
DPL(f)	16		12		38		35
ACE(g)	2		5		5		13
Other	2		2		2		3
Total operating revenues from affiliates (Generation)	$	271	$	252	$	601	$	569

__________

(a) Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.

(b) For the three and six months ended June 30, 2020 , respectively, ComEd’s Purchased power from Generation of $84 million and $181 million is recorded as Operating revenues from ComEd of $80 million and $170 million and as Purchased power and fuel from ComEd of $4 million and $11 million at Generation. For the three and six months ended June 30, 2019 , respectively, ComEd’s Purchased power from Generation of $90 million and $187 million is recorded as Operating revenues from ComEd of $89 million and $183 million and as Purchased power and fuel from ComEd of $1 million and $4 million at Generation.

(c) Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs.

137

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 18 — Related Party Transactions

(d) Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.

(e) Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.

(f) Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.

(g) Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.

PHI

PHI’s Operating revenues from affiliates are primarily with BSC for services that PHISCO provides to BSC.

Operating and maintenance expense from affiliates

The Registrants receive a variety of corporate support services from BSC. Pepco, DPL and ACE also receive corporate support services from PHISCO. See Note 1 - Significant Accounting Policies for additional information regarding BSC and PHISCO.

The following table presents the service company costs allocated to the Registrants:

	Operating and maintenance from affiliates								Capitalized costs
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019		2020		2019		2020		2019
Exelon
BSC									$	129	$	132	$	242	$	232
PHISCO									16		19		30		40
Generation
BSC	$	133	$	148	$	273	$	297	14		14		25		26
ComEd
BSC	67		60		138		122		41		36		83		61
PECO
BSC	36		37		73		74		18		24		33		46
BGE
BSC	40		39		82		77		30		38		58		59
PHI
BSC	35		34		72		66		26		20		43		40
PHISCO	—		—		—		—		16		19		30		40
Pepco
BSC	20		22		41		43		9		9		15		17
PHISCO	32		31		62		63		7		9		13		17
DPL
BSC	13		13		26		26		9		6		14		11
PHISCO	25		25		49		50		5		5		9		12
ACE
BSC	11		11		21		21		8		4		12		8
PHISCO	23		22		44		45		4		5		8		11

138

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 18 — Related Party Transactions

Current Receivables from/Payables to affiliates

The following tables present current receivables from affiliates and current payables to affiliates:

June 30, 2020

	Receivables from affiliates:
Payables to affiliates:	Generation			ComEd		PECO		BGE		Pepco		DPL		ACE		BSC		PHISCO		Other		Total
Generation				$	16	$	—	$	—	$	—	$	—	$	—	$	75	$	—	$	22	$	113
ComEd	$	49	(a)			—		—		—		—		—		42		—		8		99
PECO	20			6				—		—		1		—		25		—		5		57
BGE	11			—		—				—		—		—		28		—		2		41
PHI	—			—		—		—		—		—		—		4		—		10		14
Pepco	15			—		—		—				—		—		12		18		1		46
DPL	3			—		—		—		2				—		10		11		1		27
ACE	11			—		—		—		—		—				8		11		1		31
Other	9			1		—		—		—		—		1		—		—				11
Total	$	118		$	23	$	—	$	—	$	2	$	1	$	1	$	204	$	40	$	50	$	439

December 31, 2019

	Receivables from affiliates:
Payables to affiliates:	Generation			ComEd		PECO		BGE		Pepco		DPL		ACE		BSC		PHISCO		Other		Total
Generation				$	27	$	—	$	—	$	—	$	—	$	—	$	67	$	—	$	23	$	117
ComEd	$	78	(a)			—		—		—		—		—		54		—		8		140
PECO	27			—				—		—		—		—		25		—		3		55
BGE	28			—		—				—		—		—		34		—		4		66
PHI	—			—		—		—		—		—		—		4		—		10		14
Pepco	34			—		—		—				—		—		16		15		1		66
DPL	7			—		—		—		—				3		10		11		1		32
ACE	7			—		—		—		—		—				7		10		1		25
Other	9			1		1		1		—		—		1		—		—				13
Total	$	190		$	28	$	1	$	1	$	—	$	—	$	4	$	217	$	36	$	51	$	528

__________

(a) As of June 30, 2020 and December 31, 2019, Generation had a contract liability with ComEd for $7 million and $37 million, respectively, that was included in Other current liabilities on Generation’s Consolidated Balance Sheets. At June 30, 2020 and December 31, 2019, ComEd had a Current Payable to Generation of $42 million and $41 million, respectively, on its Consolidated Balance Sheets, which consisted of Generation’s Current Receivable from ComEd, partially offset by Generation’s contract liability with ComEd.

Borrowings from Exelon/PHI intercompany money pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. Generation, ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL and ACE participate in the PHI intercompany money pool.

Noncurrent Receivables from/Payables to affiliates

139

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 18 — Related Party Transactions

Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information.

The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation:

	June 30, 2020		December 31, 2019
ComEd	$	2,374	$	2,622
PECO	376		480
Other	1		1
Total:	$	2,751	$	3,103

Long-term debt to financing trusts

The following table presents Long-term debt to financing trusts:

	June 30, 2020						December 31, 2019
	Exelon		ComEd		PECO		Exelon		ComEd		PECO
ComEd Financing III	$	206	$	205	$	—	$	206	$	205	$	—
PECO Trust III	81		—		81		81		—		81
PECO Trust IV	103		—		103		103		—		103
Total	$	390	$	205	$	184	$	390	$	205	$	184

Long-term debt to affiliates

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate.

19. Subsequent Events (Exelon, PHI, Pepco, DPL, and ACE)

Sale of Transmission Tower Attachment Agreements

On July 1, 2020, Pepco, DPL and ACE each entered into an agreement to sell a 60% undivided interest in their respective portfolios of transmission tower attachment agreements with telecommunications companies to an unrelated owner and manager of communication infrastructure (the Buyer). As part of the transaction, the Buyer will manage the day-to-day operations of the jointly-owned agreements with telecommunications companies for a period of 35 years. In addition, for an initial period of three years for two, two-year extensions that are subject to certain conditions, the Buyer has the exclusive right to enter into new agreements with telecommunications companies and to receive a 30% undivided interest in those new agreements. As a result of the transaction, Pepco, DPL, and ACE received cash and recorded liabilities of $98 million, $13 million, and $13 million, respectively, in the third quarter of 2020.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

Exelon

Executive Overview

Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.

Exelon has eleven reportable segments consisting of Generation’s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL and ACE. See Note 1 — Significant Accounting Policies and Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.

Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.

COVID-19. The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. The Registrants provide a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of exposure to the virus. The Registrants have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities. We have implemented work from home policies where appropriate, and imposed travel limitations on our employees. In addition, the Registrants have updated existing business continuity plans in the context of this pandemic.

The Registrants continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers.

There have been no changes in internal control over financial reporting to date in 2020 as of result of COVID-19 that materially affected, or are reasonably likely to materially affect, any of the Registrants’ internal control over financial reporting. See Item 4. Controls and Procedures for additional information.

The estimated impact to Generation’s and the Utility Registrants’ Net income as a result of COVID-19 is approximately $100 million and $50 million, respectively, for the three and six months ended June 30, 2020 and primarily reflects the impact of reduction in load, incremental credit loss expense and direct costs related to COVID-19 as further discussed below.

Unfavorable economic conditions due to COVID-19 have impacted the demand for electricity and natural gas in the second quarter of 2020 and are expected to continue to impact demand in the second half of 2020. Commercial and Industrial customer demand has experienced a notable decrease, while residential demand has slightly increased. Generation and the Utility Registrants estimate a net decrease in Net income due to reduction in load of $50 to $100 million and $10 to $25 million, respectively, in the second half of 2020. Generation and the Utility Registrants load forecasts are highly dependent on many factors including, but not limited to, the duration of remaining restrictions and the speed and strength of the economic recovery. A 1% change in load would result in the following change in Net income in the second half of 2020:

141

	Generation’s Net Income		Utility Registrants’ Net Income
Commercial & Industrial Customers	$	8	$	4
Residential Customers	4		4

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

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

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

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

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

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

142

COVID-19 may impact the Registrants’ ability to operate their generating and transmission and distribution assets, the ability to access capital markets, and results of operations, including demand for electricity and natural gas, will depend on the spread and proliferation of COVID-19 around the world and future developments, which are highly uncertain and cannot be predicted at this time.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the three and six months ended June 30, 2020 compared to the same period in 2019. For additional information regarding the financial results for the three and six months ended June 30, 2020 and 2019 see the discussions of Results of Operations by Registrant.

	Three Months Ended June 30,				Favorable (unfavorable) variance			Six Months Ended June 30,						Favorable (unfavorable) variance
	2020		2019					2020			2019
Exelon	521		484		$	37		$	1,103		$	1,391		$	(288	)
Generation	476		108		368			521			472			49
ComEd	(61	)	186		(247		)	107			344			(237		)
PECO	39		102		(63		)	178			270			(92		)
BGE	39		45		(6		)	219			206			13
PHI	94		106		(12		)	202			223			(21		)
Pepco	57		64		(7		)	109			119			(10		)
DPL	19		30		(11		)	64			83			(19		)
ACE	18		14		4			31			24			7
Other(a)	(66	)	(63	)	(3		)	(124		)	(124		)	—

__________

(a) Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities.

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income attributable to common shareholders increased by $37 million and diluted earnings per average common share increased to $0.53 in 2020 from $0.50 in 2019 primarily due to:

• Higher net unrealized and realized gains on NDT funds;

• Higher mark-to-market gains;

• Lower operating and maintenance expense primarily due to lower contracting costs at Generation; and

• Favorable weather conditions at PECO and DPL Delaware.

The increases were partially offset by:

• Payments that ComEd will make under the Deferred Prosecution Agreement.  See Note 14 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information;

• Lower capacity revenue;

• Reduction in load due to COVID-19 at Generation;

• Higher storm costs related to the June 2020 storms at PECO;

• Higher credit loss expense that includes the impacts of COVID-19 at Generation, PECO, Pepco and DPL;

• COVID-19 direct costs; and

• Lower electric distribution earnings at ComEd primarily due to distribution formula rate timing.

143

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income attributable to common shareholders decreased by $288 million and diluted earnings per average common share decreased to $1.13 in 2020 from $1.43 in 2019 primarily due to:

• Payments that ComEd will make under the Deferred Prosecution Agreement.  See Note 14 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information;

• Higher net unrealized and realized losses on NDT funds;

• Lower capacity revenue;

• Reduction in load due to COVID-19 at Generation;

• Higher nuclear outage days;

• Higher storm costs related to the June 2020 storms at PECO;

• Higher credit loss expense that includes the impacts of COVID-19 at Generation, PECO, Pepco, and DPL;

• COVID-19 direct costs;

• Unfavorable weather conditions at PECO and ACE; and

• Lower allowed electric distribution ROE due to a decrease in treasury rates.

The decreases were partially offset by:

• Higher mark-to-market gains;

• Lower operating and maintenance expense primarily due to previous cost management programs and lower contracting costs at Generation;

• The approval of the New Jersey ZEC program in the second quarter of 2019;

• An income tax settlement at Generation; and

• Regulatory rate increases at BGE and ACE.

Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

144

The following tables provide a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and six months ended June 30, 2020 compared to the same period in 2019.

	Three Months Ended June 30,
	2020						2019
(All amounts in millions after tax)				Earnings per Diluted Share						Earnings per Diluted Share
Net Income Attributable to Common Shareholders	$	521		$	0.53		$	484		$	0.50
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $18 and $22, respectively)	(51		)	(0.05		)	68			0.07
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $275 and $28, respectively)(a)	(305		)	(0.31		)	52			0.05
Asset Impairments (net of taxes of $7 and $1, respectively)(b)	19			0.02			1			—
Plant Retirements and Divestitures (net of taxes of $2 and $37, respectively)(c)	7			0.01			(24		)	(0.02		)
Cost Management Program (net of taxes of $3 and $1, respectively)(d)	6			0.01			6			0.01
Litigation Settlement Gain (net of taxes of $7)	—			—			(19		)	(0.02		)
Change in Environmental Liabilities (net of taxes of $0)	1			—			—			—
COVID-19 Direct Costs (net of taxes of $10)(e)	27			0.03			—			—
Deferred Prosecution Agreement Payments (net of taxes of $0)(f)	200			0.20			—			—
Income Tax-Related Adjustments (entire amount represents tax expense)	5			0.01			—			—
Noncontrolling Interests (net of taxes of $20 and $3, respectively)(g)	104			0.11			15			0.02
Adjusted (non-GAAP) Operating Earnings	$	536		$	0.55		$	583		$	0.60

145

	Six Months Ended June 30,
	2020						2019
(All amounts in millions after tax)				Earnings per Diluted Share						Earnings per Diluted Share
Net Income Attributable to Common Shareholders	$	1,103		$	1.13		$	1,391		$	1.43
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $50 and $34, respectively)	(146		)	(0.15		)	98			0.10
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $130 and $133, respectively)(a)	180			0.18			(142		)	(0.15		)
Asset Impairments (net of taxes of $7 and $2, respectively)(b)	21			0.02			6			0.01
Plant Retirements and Divestitures (net of taxes of $6 and $32, respectively)(c)	20			0.02			(4		)	—
Cost Management Program (net of taxes of $6 and $7, respectively)(d)	17			0.02			16			0.02
Litigation Settlement Gain (net of taxes of $7)	—			—			(19		)	(0.02		)
Change in Environmental Liabilities (net of taxes of $0)	1			—			—			—
COVID-19 Direct Costs (net of taxes of $10)(e)	27			0.03			—			—
Deferred Prosecution Agreement Payments (net of taxes of $0)(f)	200			0.20			—			—
Income Tax-Related Adjustments (entire amount represents tax expense)	4			—			—			—
Noncontrolling Interests (net of taxes of $10 and $15, respectively)(g)	(40		)	(0.04		)	82			0.08
Adjusted (non-GAAP) Operating Earnings	$	1,387		$	1.42		$	1,429		$	1.47

__________

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2020 and 2019 ranged from 26.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 47.4% and 35.1% for the three months ended June 30, 2020 and 2019, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 41.9% and 48.4% for the six months ended June 30, 2020 and 2019, respectively.

(a) Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.

(b) Reflects an impairment at ComEd related to the acquisition of transmission assets and the impairment of certain wind assets at Generation.

(c) In 2019, primarily reflects net realized gains related to Oyster Creek's NDT fund investments in conjunction with the Holtec sale on July 1, 2019 and a gain on the sale of certain wind assets, partially offset by accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility. In 2020, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of certain fossil sites.

(d) Primarily represents reorganization costs related to cost management programs.

(e) Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.

(f) Reflects the payments that ComEd will make under the Deferred Prosecution Agreement. See Note 14 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

(g) Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units.

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Significant 2020 Transactions and Developments

Deferred Prosecution Agreement

On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into ComEd’s lobbying activities in the State of Illinois. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the United States Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date. The payments will not be recovered in rates or charged to customers, and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon.

Utility Rates and Base Rate Proceedings

The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2020. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.

Completed Distribution Base Rate Case Proceedings

Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Approved Revenue Requirement (Decrease) Increase			Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois (Electric)	April 8, 2019	$	(6	)	$	(17	)	8.91	%	December 4, 2019	January 1, 2020
DPL - Maryland (Electric)	December 5, 2019 (amended April 23, 2020)	17			12			9.60	%	July 14, 2020	July 16, 2020

147

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Requested ROE		Expected Approval Timing
ComEd - Illinois (Electric)	April 16, 2020	$	(11	)	8.38	%	Fourth quarter of 2020
BGE - Maryland (Electric and Natural Gas)	May 15, 2020	235			10.1	%	Fourth quarter of 2020
Pepco - District of Columbia (Electric)	May 30, 2019 (amended June 1, 2020)	136			9.7	%	Fourth quarter of 2020
DPL - Delaware (Natural Gas)	February 21, 2020 (amended March 17, 2020)	9			10.3	%	First quarter of 2021
DPL - Delaware (Electric)	March 6, 2020 (amended April 16, 2020)	24			10.3	%	Second quarter of 2021

Transmission Formula Rates

Transmission Formula Rate (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or before May 15 and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd, BGE, DPL and ACE is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for Pepco is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense and accumulated deferred income taxes. The update for ComEd, BGE, DPL and ACE also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The update for PECO and Pepco also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).

For 2020, the following total increases/(decreases) were included in ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:

Registrant	Initial Revenue Requirement Increase (Decrease)			Annual Reconciliation Decrease			Total Revenue Requirement Increase (Decrease)			Allowed Return on Rate Base		Allowed ROE
ComEd	$	18		$	(4	)	$	14		8.17	%	11.50	%
PECO	5			(28		)	(23		)	7.47	%	10.35	%
BGE	16			(3		)	4			7.26	%	10.50	%
Pepco	2			(46		)	(44		)	7.81	%	10.50	%
DPL	(4		)	(40		)	(44		)	7.20	%	10.50	%
ACE	5			(25		)	(20		)	7.40	%	10.50	%

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Sales of Customer Accounts Receivable

On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by Generation, entered into an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain customer accounts receivables. Generation received approximately $500 million of cash in accordance with the initial sale of approximately $1.2 billion receivables. See Note 5 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.

Other Key Business Drivers and Management Strategies

The following discussion of other key business driver and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the Registrants' combined 2019 Form 10-K and Note 14 — Commitments and Contingencies to the Consolidated Financial Statements in this report for additional information on various environmental matters.

Power Markets

Section 232 Uranium Petition

On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce ("DOC") seeking relief under Section 232 of the Trade Expansion Act of 1962 from imports of uranium products, alleging that these imports threaten national security.

The United States Nuclear Fuel Working Group ("Working Group") report was made public on April 23, 2020. The Working Group report states that nuclear power is intrinsically tied to national security, and promises that the U.S. government will take bold actions to strengthen all parts of the nuclear fuel industry in the U.S. It recommends the Agreement Suspending the Antidumping Investigation on Uranium from the Russian Federation (the “Russian Suspension Agreement”) be extended and to consider reducing the amount of Russian imports of nuclear fuel. The Russian Suspension Agreement is the historical resolution of a 1991 DOC investigation that found that the Russians had been selling or “dumping” cheap uranium products into the U.S. The Russian Suspension Agreement has been amended several times in the intervening years to allow Russia to supply limited amounts of uranium products into the U.S.  It was set to expire at the end of 2020, but the U.S. government has expressed interest in continuing the limitations on Russian imports by renegotiating the Russian Suspension Agreement.

The Working Group report should be viewed as policy recommendations that may be implemented by executive agencies, congress and or regulatory bodies. Negotiations between the DOC and the Russians on an extension of the Russian Suspension Agreement are in progress at this time, and may result in a reduction in the amount of uranium that can be imported from Russia, which may have the effect of reducing the diversity of supply available to Exelon for uranium, enrichment and conversion services purchases. Exelon and Generation cannot currently predict the outcome of the policy changes recommended by the Working Group.

Hedging Strategy

Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. As of June 30, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 98%-101% and 76%-79% for 2020 and 2021, respectively. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.

Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 60% of Generation’s uranium concentrate requirements from

149

2020 through 2024 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.

See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and Item 3. Quantitative and Qualitative Disclosures about Market Risk for additional information.

The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.

Environmental Legislative and Regulatory Developments

Air Quality

Mercury and Air Toxics Standards Rule (MATS). On December 16, 2011, the EPA signed a final rule, known as MATS, to reduce emissions of hazardous air pollutants from power plants. MATS requires coal-fired power plants to achieve high removal rates of mercury, acid gases and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. In April 2014, the U.S. Court of Appeals for the D.C. Circuit issued a decision upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate power plant emissions of hazardous air pollutants, but did not vacate MATS. In 2016, the EPA issued a supplemental finding responding to the U.S. Supreme Court’s decision; the EPA concluded that, after considering costs, it remained appropriate and necessary to regulate hazardous air pollutants from power plants. On May 22, 2020, however, the EPA reversed course, publishing a final rule revoking the "appropriate and necessary" finding underpinning MATS. A coal mining company filed a lawsuit in the U.S. D.C. Circuit court seeking vacatur of MATS based on EPA’s May 22, 2020 ruling. On June 22, 2020, Exelon and two other entities filed a motion to intervene in that lawsuit to defend MATS, and on July 21, 2020, they separately filed a lawsuit in the D.C. Circuit court challenging the EPA’s May 22, 2020 rescission of the appropriate and necessary finding underpinning MATS.

The Clean Power Plan and Affordable Clean Energy Rule. The EPA’s 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide emissions from existing fossil-fired power plants under Clean Air Act Section 111(d). The CPP’s carbon pollution limits could be met through changes to the electric generation system, including shifting generation from higher-emitting units to lower- or zero-emitting units, as well as the development of new or expanded zero-emissions generation. In July 2019, the EPA published its final the Affordable Clean Energy rule, which repealed the CPP and replaced it with less stringent emissions guidelines for existing fossil-fired power plants based on heat rate improvement measures that could be achieved within the fence line of individual plants. Exelon, together with a coalition of other electric utilities, filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit on September 6, 2019, challenging the Affordable Clean Energy rule as unlawful. This lawsuit has been consolidated with separate challenges to the Affordable Clean Energy rule filed by various states, non-governmental organizations, and business coalitions.

Employees

In June 2020, Generation, ComEd, and DPL ratified or extended CBAs as follows:

• Generation ratified its CBA with SPFPA Local 238, which covers 122 security officers at Quad Cities.  The CBA expires in 2023.  

• ComEd extended its CBA with IBEW Local 15 to 2022, which covers 80 employees in the System Services Group.  

• DPL ratified its CBAs with IBEW Locals 1238 and 1307, which together cover 857 employees. Both CBAs expire in 2024.

150

Critical Accounting Policies and Estimates

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

Results of Operations by Registrant

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Generation

Results of Operations — Generation

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

	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						(Unfavorable) Favorable Variance
	2020			2019						2020			2019
Operating revenues	$	3,880		$	4,210		$	(330	)	$	8,613		$	9,506		$	(893	)
Purchased power and fuel expense	1,942			2,292			350			4,646			5,497			851
Revenues net of purchased power and fuel expense	1,938			1,918			20			3,967			4,009			(42		)
Other operating expenses
Operating and maintenance	1,189			1,266			77			2,451			2,484			33
Depreciation and amortization	300			409			109			604			814			210
Taxes other than income taxes	116			129			13			246			264			18
Total other operating expenses	1,605			1,804			199			3,301			3,562			261
Gain on sales of assets and businesses	12			33			(21		)	12			33			(21		)
Operating income	345			147			198			678			480			198
Other income and (deductions)
Interest expense, net	(87		)	(116		)	29			(197		)	(227		)	30
Other, net	602			171			431			(168		)	601			(769		)
Total other income and (deductions)	515			55			460			(365		)	374			(739		)
Income before income taxes	860			202			658			313			854			(541		)
Income taxes	329			78			(251		)	(59		)	301			360
Equity in losses of unconsolidated affiliates	(2		)	(6		)	4			(4		)	(13		)	9
Net income	529			118			411			368			540			(172		)
Net income (loss) attributable to noncontrolling interests	53			10			43			(153		)	68			(221		)
Net income attributable to membership interest	$	476		$	108		$	368		$	521		$	472		$	49

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income attributable to membership interest increased $368 million by primarily due to:

• Higher net unrealized and realized gains on NDT funds;

• Higher mark-to-market gains; and

• Lower operating and maintenance expense primarily due to lower contracting costs.

The increases were partially offset by:

• Lower capacity revenue;

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Generation

• Reduction in load due to COVID-19;

• COVID-19 direct costs; and

• Higher credit loss expense that includes the impacts of COVID-19.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income attributable to membership interest increased $49 million by primarily due to:

• Higher mark-to-market gains;

• Lower operating and maintenance expense primarily due to previous cost management programs and lower contracting costs;

• The approval of the New Jersey ZEC program in the second quarter of 2019; and

• An income tax settlement.

The increases were partially offset by:

• Higher net unrealized and realized losses on NDT funds;

• Lower capacity revenue;

• Reduction in load due to COVID-19;

• Higher nuclear outage days;

• COVID-19 direct costs; and

• Higher credit loss expense that includes the impacts of COVID-19.

Revenues Net of Purchased Power and Fuel Expense. The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned with these same geographic regions. Generation's five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. See Note 4 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.

The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall operating revenues or results of operations. Further, the following activities are not allocated to a region and are reported in Other: accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.

Generation evaluates the operating performance of electric business activities using the measure of RNF. Operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.

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Generation

For the three and six months ended June 30, 2020 compared to 2019, RNF by region were as follows. See Note 4 - Segment Information of the Combined Notes to the Consolidated Financial Statements for additional information on Purchase power and fuel expense for Generation’s reportable segments.

	Three Months Ended June 30,					Variance			% Change		Six Months Ended June 30,					Variance			% Change
	2020		2019								2020		2019
Mid-Atlantic(a)	$	525	$	652		$	(127	)	(19.5	)%	$	1,092	$	1,334		$	(242	)	(18.1	)%
Midwest(b)	703		730			(27		)	(3.7	)%	1,427		1,500			(73		)	(4.9	)%
New York	246		253			(7		)	(2.8	)%	440		519			(79		)	(15.2	)%
ERCOT	97		79			18			22.8	%	177		154			23			14.9	%
Other Power Regions	157		134			23			17.2	%	312		292			20			6.8	%
Total electric revenues net of purchased power and fuel expense	1,728		1,848			(120		)	(6.5	)%	3,448		3,799			(351		)	(9.2	)%
Mark-to-market gains (losses)	85		(74		)	159			214.9	%	218		(102		)	320			313.7	%
Other	125		144			(19		)	(13.2	)%	301		312			(11		)	(3.5	)%
Total revenue net of purchased power and fuel expense	$	1,938	$	1,918		$	20		1.0	%	$	3,967	$	4,009		$	(42	)	(1.0	)%

_________

(a) Includes results of transactions with PECO, BGE, Pepco, DPL and ACE.

(b) Includes results of transactions with ComEd.

154

Generation

Generation’s supply sources by region are summarized below:

	Three Months Ended June 30,		Variance		% Change		Six Months Ended June 30,		Variance		% Change
Supply Source (GWhs)	2020	2019					2020	2019
Nuclear Generation(a)
Mid-Atlantic	13,167	14,075	(908	)	(6.5	)%	25,951	29,155	(3,204	)	(11.0	)%
Midwest	23,860	23,996	(136	)	(0.6	)%	47,458	47,729	(271	)	(0.6	)%
New York	6,389	6,677	(288	)	(4.3	)%	12,562	13,579	(1,017	)	(7.5	)%
Total Nuclear Generation	43,416	44,748	(1,332	)	(3.0	)%	85,971	90,463	(4,492	)	(5.0	)%
Fossil and Renewables
Mid-Atlantic	707	915	(208	)	(22.7	)%	1,560	1,865	(305	)	(16.4	)%
Midwest	268	328	(60	)	(18.3	)%	656	719	(63	)	(8.8	)%
New York	1	1	—		—	%	2	2	—		—	%
ERCOT	3,251	3,066	185		6.0	%	6,263	6,144	119		1.9	%
Other Power Regions	2,603	2,514	89		3.5	%	6,110	5,654	456		8.1	%
Total Fossil and Renewables	6,830	6,824	6		0.1	%	14,591	14,384	207		1.4	%
Purchased Power
Mid-Atlantic	3,730	2,557	1,173		45.9	%	9,672	5,123	4,549		88.8	%
Midwest	236	250	(14	)	(5.6	)%	524	538	(14	)	(2.6	)%
ERCOT	1,255	1,213	42		3.5	%	2,246	2,255	(9	)	(0.4	)%
Other Power Regions	11,303	11,116	187		1.7	%	23,469	23,684	(215	)	(0.9	)%
Total Purchased Power	16,524	15,136	1,388		9.2	%	35,911	31,600	4,311		13.6	%
Total Supply/Sales by Region(c)
Mid-Atlantic(b)	17,604	17,547	57		0.3	%	37,183	36,143	1,040		2.9	%
Midwest(b)	24,364	24,574	(210	)	(0.9	)%	48,638	48,986	(348	)	(0.7	)%
New York	6,390	6,678	(288	)	(4.3	)%	12,564	13,581	(1,017	)	(7.5	)%
ERCOT	4,506	4,279	227		5.3	%	8,509	8,399	110		1.3	%
Other Power Regions	13,906	13,630	276		2.0	%	29,579	29,338	241		0.8	%
Total Supply/Sales by Region	66,770	66,708	62		0.1	%	136,473	136,447	26		—	%

_________

(a) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG).

(b) Includes affiliate sales to PECO, BGE, Pepco, DPL and ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

(c) Reflects a decrease in load due to COVID-19.

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Generation

For the three and six months ended June 30, 2020 compared to 2019, changes in RNF by region were as follows:

	Increase/ (Decrease)			Three Months Ended June 30, 2020	Increase/ (Decrease)			Six Months Ended June 30, 2020
Mid-Atlantic	$	(127	)	• decreased capacity revenue • decreased revenue due to permanent cease of generation operations at Three Mile Island in the third quarter of 2019 • decreased load due to COVID-19 • lower realized energy prices, partially offset by • increased ZEC revenues due to decreased nuclear outage days at Salem	$	(242	)	• decreased capacity revenue • decreased revenue due to permanent cease of generation operations at Three Mile Island in the third quarter of 2019 • decreased load due to COVID-19 • lower realized energy prices, partially offset by • increased ZEC revenues due to the approval of the NJ ZEC program in the second quarter of 2019
Midwest	(27		)	• decreased capacity revenue • decreased load due to COVID-19 • lower realized energy prices	(73		)	• decreased capacity revenue • decreased load due to COVID-19 • lower realized energy prices
New York	(7		)	• decreased load due to COVID-19 • lower realized energy prices, partially offset by • increased capacity revenues	(79		)	• decreased load due to COVID-19 • lower realized energy prices • increased nuclear outage days
ERCOT	18			• higher portfolio optimization, partially offset by • decreased load due to COVID-19	23			• higher portfolio optimization partially offset by • decreased load due to COVID-19
Other Power Regions	23			• higher portfolio optimization, partially offset by • decreased capacity revenue • decreased load due to COVID-19	20			• higher portfolio optimization, partially offset by • decreased capacity revenue • decreased load due to COVID-19
Mark-to-market(a)	159			• gains on economic hedging activities of $85 million in 2020 compared to losses of $74 million in 2019	320			• gains on economic hedging activities of $218 million in 2020 compared to losses of $102 million in 2019
Other	(19		)	• decreased revenue related to the energy efficiency business	(11		)	• decreased revenue related to the energy efficiency business
Total	$	20			$	(42	)

_________

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

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Generation

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
Nuclear fleet capacity factor	95.4	%	95.1	%	94.7	%	96.1	%
Refueling outage days	92		56		186		130
Non-refueling outage days	—		28		11		28

The changes in Operating and maintenance expense consisted of the following:

	Three Months Ended June 30, 2020			Six Months Ended June 30, 2020
	Increase (Decrease)			Increase (Decrease)
Litigation Settlements	$	26		$	26
COVID-19 Direct Costs	23			23
Nuclear refueling outage costs, including the co-owned Salem plants	12			54
Credit loss expense(a)	12			17
Asset Impairments	9			5
Pension and non-pension postretirement benefits expense	(4		)	(9		)
Accretion expense	(5		)	(15		)
Other	(9		)	(4		)
Travel and Entertainment	(11		)	(12		)
Plant retirements and divestitures	(13		)	69
Corporate allocations	(16		)	(27		)
Labor, other benefits, contracting and materials(b)	(101		)	(160		)
Increase in operating and maintenance expense	$	(77	)	$	(33	)

_________ 

(a) Increased credit loss expense including impacts from COVID-19.

(b) Primarily reflects decreased costs related to the permanent cease of generation operations at TMI and lower labor costs resulting from previous cost management programs.

Depreciation and amortization expense for the three and six months ended June 30, 2020 compared to the same period in 2019 decreased primarily due to the permanent cease of generation operations at Three Mile Island in the third quarter of 2019.

Taxes other than income taxes for the three and six months ended June 30, 2020 compared to the same period in 2019 decreased primarily due to decreased sales and power usage.

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

Interest Expense for the three and six months ended June 30, 2020 compared to the same period in 2019 decreased primarily due to the maturity of long-term debt in the first and second quarter of 2020.

157

Generation

Other, net for the three months ended June 30, 2020 compared to the same period in 2019 increased and for the six months ended June 30, 2020 compared to the same period in 2019 decreased due to activity associated with NDT funds as described in the table below:

	Three Months Ended June 30,						Six Months Ended June 30,
	2020			2019			2020			2019
Net unrealized (losses) gains on NDT funds(a)	$	452		$	(98	)	$	(253	)	$	182
Net realized gains on sale of NDT funds(a)	3			193			58			222
Interest and dividend income on NDT funds(a)	19			36			46			61
Contractual elimination of income tax expense(b)	134			34			(43		)	120
Other	(6		)	6			24			16
Total other, net	$	602		$	171		$	(168	)	$	601

_________ 

(a) Unrealized gains (losses), realized gains and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement units.

(b) Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement units.

Effective income tax rates were 38.3% and 38.6% for the three months ended June 30, 2020 and 2019, respectively. Generation's effective income tax rates were (18.8)% and 35.2% for the six months ended June 30, 2020 and 2019, respectively. The change primarily reflects one-time tax settlements. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information

Net income attributable to noncontrolling interests for the three months ended June 30, 2020 compared to the same period in 2019 increased primarily due to higher net gains on NDT fund investments for CENG and for the six months ended June 30, 2020 compared to the same period in 2019 decreased primarily due to unrealized losses on NDT fund investments for CENG.

158

ComEd

Results of Operations — ComEd

	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2020			2019						2020			2019
Operating revenues	$	1,417		$	1,351		$	66		$	2,856		$	2,759		$	97
Operating expenses
Purchased power expense	464			407			(57		)	951			892			(59		)
Operating and maintenance	536			305			(231		)	853			626			(227		)
Depreciation and amortization	274			257			(17		)	547			508			(39		)
Taxes other than income taxes	71			71			—			146			148			2
Total operating expenses	1,345			1,040			(305		)	2,497			2,174			(323		)
Gain on sales of assets	—			—			—			—			3			(3		)
Operating income	72			311			(239		)	359			588			(229		)
Other income and (deductions)
Interest expense, net	(98		)	(89		)	(9		)	(192		)	(178		)	(14		)
Other, net	11			10			1			22			19			3
Total other income and (deductions)	(87		)	(79		)	(8		)	(170		)	(159		)	(11		)
(Loss) income before income taxes	(15		)	232			(247		)	189			429			(240		)
Income taxes	46			46			—			82			85			3
Net (loss) income	$	(61	)	$	186		$	(247	)	$	107		$	344		$	(237	)

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income decreased $247 million as compared to the same period in 2019, primarily due to payments that ComEd will make under the Deferred Prosecution Agreement, an impairment charge resulting from acquisition of transmission assets, and distribution formula rate timing. See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income decreased $237 million as compared to the same period in 2019, primarily due to payments that ComEd will make under the Deferred Prosecution Agreement, an impairment charge resulting from acquisition of transmission assets, and lower allowed electric distribution ROE due to a decrease in treasury rates, partially offset by higher electric distribution formula rate earnings (reflecting the impacts of higher rate base). See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.

The changes in Operating revenues consisted of the following:

	Three Months Ended June 30, 2020			Six Months Ended June 30, 2020
	Increase (Decrease)			Increase (Decrease)
Electric distribution	$	—		$	21
Transmission	(4		)	(12		)
Energy efficiency	6			19
	2			28
Regulatory required programs	64			69
Total increase	$	66		$	97

159

ComEd

Revenue Decoupling. The demand for electricity is affected by weather conditions and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer or number of customers as a result of a change to the electric distribution formula rate pursuant to FEJA.

Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue for the three months ended June 30, 2020 compared to the same period in 2019 remained relatively consistent. Electric distribution revenue increased during the six months ended June 30, 2020 as compared to the same period in 2019, primarily due to the impact of higher rate base and higher fully recoverable costs, offset by lower allowed ROE due to a decrease in treasury rates. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the three and six months ended June 30, 2020 as compared to the same period in 2019, primarily due to the impact of decreased peak load partially offset by higher fully recoverable costs. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the three and six months ended June 30, 2020 as compared to the same period in 2019, primarily due to the increased regulatory asset amortization. See Depreciation and amortization expense discussions below and Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, and costs related to electricity, ZEC and REC procurement. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to electricity, ZEC and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. ComEd recovers electricity, ZEC and REC procurement costs from customers without mark-up.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

The increase of $57 million and $59 million for the three and six months ended June 30, 2020 compared to the same period in 2019, respectively, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

160

ComEd

The changes in Operating and maintenance expense consisted of the following:

	Three Months Ended June 30, 2020		Six Months Ended June 30, 2020
	Increase (Decrease)		(Decrease) Increase
Deferred Prosecution Agreement payments(a)	$	200	$	200
Storm-related costs	9		2
BSC costs	6		16
Pension and non-pension postretirement benefits expense	2		4
Labor, other benefits, contracting and materials	1		(9		)
Other(b)	10		13
	228		226
Regulatory required programs(c)	3		1
Total increase	$	231	$	227

__________

(a) See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

(b) Primarily reflects impairment charge related to acquisition of transmission assets.

(c) ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism. During the three and six months ended June 30, 2020, ComEd recorded a net increase in credit losses account due to the timing of regulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenues for the period presented.

The changes in Depreciation and amortization expense consisted of the following:

	Three Months Ended June 30, 2020		Six Months Ended June 30, 2020
	Increase		Increase
Depreciation and amortization(a)	$	14	$	28
Regulatory asset amortization(b)	3		11
Total increase	$	17	$	39

_________

(a) Reflects ongoing capital expenditures.

(b) Includes amortization of ComEd's energy efficiency formula rate regulatory asset.

Effective income tax rate were (306.7)% and 19.8% for the three months ended June 30, 2020 and 2019, respectively, and 43.4% and 19.8% for the six months ended June 30, 2020 and 2019. See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

161

PECO

Results of Operations — PECO

	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2020			2019						2020			2019
Operating revenues	$	681		$	655		$	26		$	1,493		$	1,554		$	(61	)
Operating expenses
Purchased power and fuel expense	216			191			(25		)	499			520			21
Operating and maintenance	275			199			(76		)	492			424			(68		)
Depreciation and amortization	88			83			(5		)	173			164			(9		)
Taxes other than income taxes	39			37			(2		)	78			79			1
Total operating expenses	618			510			(108		)	1,242			1,187			(55		)
Operating income	63			145			(82		)	251			367			(116		)
Other income and (deductions)
Interest expense, net	(36		)	(33		)	(3		)	(71		)	(67		)	(4		)
Other, net	5			3			2			7			7			—
Total other income and (deductions)	(31		)	(30		)	(1		)	(64		)	(60		)	(4		)
Income before income taxes	32			115			(83		)	187			307			(120		)
Income taxes	(7		)	13			20			9			37			28
Net income	$	39		$	102		$	(63	)	$	178		$	270		$	(92	)

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income decreased by $63 million primarily due to higher storm costs due to June 2020 storms and an increase in credit loss expense including the impacts of COVID-19, partially offset by favorable weather conditions.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income decreased by $92 million primarily due to unfavorable weather conditions, higher storm costs due to June 2020 storms, and an increase in credit loss expense including the impacts of COVID-19.

The changes in Operating revenues consisted of the following:

	Three Months Ended June 30, 2020									Six Months Ended June 30, 2020
	Increase (Decrease)									Increase (Decrease)
	Electric			Gas			Total			Electric			Gas			Total
Weather	$	3		$	8		$	11		$	(23	)	$	(13	)	$	(36	)
Volume	3			(3		)	—			(4		)	(6		)	(10		)
Pricing	(2		)	1			(1		)	6			5			11
Transmission	—			—			—			2			—			2
Other	(4		)	—			(4		)	(4		)	(1		)	(5		)
	—			6			6			(23		)	(15		)	(38		)
Regulatory required programs	20			—			20			27			(50		)	(23		)
Total increase (decrease)	$	20		$	6		$	26		$	4		$	(65	)	$	(61	)

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended June 30, 2020 compared to the same period in 2019, Operating revenues related to weather increased by the impact of favorable weather conditions in PECO's service territory. During the six months ended

162

PECO

June 30, 2020 compared to the same period in 2019, Operating revenues related to weather decreased by the impact of unfavorable weather conditions in PECO's service territory.

Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and six months ended June 30, 2020 compared to the same period in 2019 and normal weather consisted of the following:

Heating and Cooling Degree-Days			Normal	% Change
Three Months Ended June 30,	2020	2019		From 2019		2020 vs. Normal
Heating Degree-Days	568	270	432	110.4	%	31.5	%
Cooling Degree-Days	376	425	386	(11.5	)%	(2.6	)%
Six Months Ended June 30,
Heating Degree-Days	2,557	2,702	2,850	(5.4	)%	(10.3	)%
Cooling Degree-Days	376	427	387	(11.9	)%	(2.8	)%

Volume. Electric volume, exclusive of the effects of weather, for the three months ended June 30, 2020 compared to the same period in 2019, increased on a net basis due to an increase in usage for residential customers partially offset by a decrease for commercial and industrial customers due to COVID-19.  Residential volumes were further increased by customer growth.  Electric volume, exclusive of the effects of weather, for the six months ended June 30, 2020 compared to the same period in 2019, decreased on a net basis due to a decrease in usage for commercial and industrial customers partially offset by an increase in usage for residential customers due to COVID-19. Volumes further decreased as a result of the impact of energy efficiency initiatives across all customer classes partially offset by increases due to customer growth. Natural gas volume for the three and six months ended June 30, 2020, compared to the same period in 2019, decreased on a net basis due to a decrease in usage for the commercial and industrial natural gas classes partially offset by increased usage for the residential natural gas class due to COVID-19.

Electric Retail Deliveries to Customers (in GWhs)	Three Months Ended June 30,		% Change		Weather - Normal % Change(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change(b)
	2020	2019					2020	2019
Residential	3,143	2,821	11.4	%	8.4	%	6,397	6,462	(1.0	)%	3.3	%
Small commercial & industrial	1,571	1,823	(13.8	)%	(12.9	)%	3,476	3,889	(10.6	)%	(7.7	)%
Large commercial & industrial	3,181	3,769	(15.6	)%	(14.7	)%	6,602	7,340	(10.1	)%	(9.2	)%
Public authorities & electric railroads	112	182	(38.5	)%	(38.5	)%	263	377	(30.2	)%	(30.4	)%
Total electric retail deliveries(a)	8,007	8,595	(6.8	)%	(7.1	)%	16,738	18,068	(7.4	)%	(4.8	)%

	As of June 30,
Number of Electric Customers	2020	2019
Residential	1,501,259	1,486,973
Small commercial & industrial	154,016	153,387
Large commercial & industrial	3,096	3,105
Public authorities & electric railroads	10,119	9,733
Total	1,668,490	1,653,198

163

PECO

_________

(a) Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Natural Gas Deliveries to Customers (in mmcf)	Three Months Ended June 30,		% Change		Weather - Normal % Change(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change(b)
	2020	2019					2020	2019
Residential	6,464	3,351	92.9	%	9.3	%	23,746	24,569	(3.3	)%	1.2	%
Small commercial & industrial	2,054	4,040	(49.2	)%	(46.0	)%	10,863	14,684	(26.0	)%	(10.8	)%
Large commercial & industrial	3	17	(82.4	)%	(30.0	)%	12	36	(66.7	)%	(18.0	)%
Transportation	5,148	5,719	(10.0	)%	(16.0	)%	12,283	13,692	(10.3	)%	(8.0	)%
Total natural gas retail deliveries(a)	13,669	13,127	4.1	%	(13.7	)%	46,904	52,981	(11.5	)%	(4.3	)%

	As of June 30,
Number of Natural Gas Customers	2020	2019
Residential	489,201	483,657
Small commercial & industrial	44,189	43,953
Large commercial & industrial	6	2
Transportation	719	737
Total	534,115	528,349

_________

(a) Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.

(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Pricing for the three months ended June 30, 2020 compared to the same period in 2019 remained relatively consistent. Pricing for the six months ended June 30, 2020 compared to the same period in 2019 increased primarily due to higher overall effective rates due to decreased usage across all major customer classes. Additionally, the increase represents revenue from higher natural gas distribution rates.

Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the three and six months ended June 30, 2020 compared to the same period in 2019 remained relatively consistent.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries but impact Operating revenues related to supplied electricity and natural gas. Drivers of Operating revenues related to commodity and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. PECO recovers electricity, natural gas and REC procurement costs from customers without mark-up.

Other revenue primarily includes revenue related to late payment charges. Other revenues decreased for the three and six months ended June 30, 2020, compared to the same period in 2019, as PECO temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored service to customers upon request who were disconnected in the last twelve months.

See Note 4— Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

164

PECO

The increase of $25 million and decrease of $21 million for the three and six months ended June 30, 2020 compared to the same period in 2019, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

The changes in Operating and maintenance expense consisted of the following:

	Three Months Ended June 30, 2020			Six Months Ended June 30, 2020
	Increase (Decrease)			(Decrease) Increase
Storm-related costs(a)	$	61		$	53
Credit loss expense(b)	18			19
Labor, other benefits, contracting and materials	1			(5		)
Pension and non-pension postretirement benefits expense	(1		)	(1		)
Other	(3		)	2
Total increase	$	76		$	68

__________

(a) Reflects increased storm costs due to the June 2020 storms.

(b) Increased credit loss expense including impacts from COVID-19.

The changes in Depreciation and amortization expense consisted of the following:

	Three Months Ended June 30, 2020		Six Months Ended June 30, 2020
	Increase		Increase (Decrease)
Depreciation and amortization(a)	$	5	$	10
Regulatory asset amortization	—		(1		)
Total increase	$	5	$	9

__________

(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective Income Tax Rates were (21.9)% and 11.3% for the three months ended June 30, 2020 and 2019, respectively, and 4.8% and 12.1% for the six months ended June 30, 2020 and 2019. See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

165

BGE

Results of Operations — BGE

	Three Months Ended June 30,						(Unfavorable) Favorable Variance			Six Months Ended June 30,						(Unfavorable) Favorable Variance
	2020			2019						2020			2019
Operating revenues	$	616		$	649		$	(33	)	$	1,554		$	1,625		$	(71	)
Operating expenses
Purchased power and fuel expense	194			208			14			483			570			87
Operating and maintenance	187			182			(5		)	376			372			(4		)
Depreciation and amortization	129			117			(12		)	272			252			(20		)
Taxes other than income taxes	63			62			(1		)	132			131			(1		)
Total operating expenses	573			569			(4		)	1,263			1,325			62
Operating income	43			80			(37		)	291			300			(9		)
Other income and (deductions)
Interest expense, net	(32		)	(29		)	(3		)	(64		)	(58		)	(6		)
Other, net	6			5			1			10			11			(1		)
Total other income and (deductions)	(26		)	(24		)	(2		)	(54		)	(47		)	(7		)
Income before income taxes	17			56			(39		)	237			253			(16		)
Income taxes	(22		)	11			33			18			47			29
Net income	$	39		$	45		$	(6	)	$	219		$	206		$	13

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income remained relatively consistent.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income increased by $13 million primarily due to higher natural gas and electric distribution rates that became effective December 2019.

The changes in Operating revenues consisted of the following:

	Three Months Ended June 30, 2020									Six Months Ended June 30, 2020
	Increase (Decrease)									Increase (Decrease)
	Electric			Gas			Total			Electric			Gas			Total
Distribution	$	1		$	6		$	7		$	10		$	35		$	45
Transmission	(17		)	—			(17		)	(11		)	—			(11		)
Other	(5		)	(3		)	(8		)	(2		)	(4		)	(6		)
	(21		)	3			(18		)	(3		)	31			28
Regulatory required programs	(14		)	(1		)	(15		)	(77		)	(22		)	(99		)
Total (decrease) increase	$	(35	)	$	2		$	(33	)	$	(80	)	$	9		$	(71	)

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

166

BGE

	As of June 30,
Number of Electric Customers	2020	2019
Residential	1,185,718	1,171,815
Small commercial & industrial	114,118	113,982
Large commercial & industrial	12,416	12,275
Public authorities & electric railroads	264	264
Total	1,312,516	1,298,336

	As of June 30,
Number of Natural Gas Customers	2020	2019
Residential	643,745	634,939
Small commercial & industrial	38,255	38,164
Large commercial & industrial	6,079	5,991
Total	688,079	679,094

Distribution Revenue increased for the three and six months ended June 30, 2020, compared to the same period in 2019, primarily due to the impact of higher natural gas and electric distribution rates that became effective in December 2019. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the three and six months ended June 30, 2020, compared to the same period in 2019, primarily due to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Other revenue includes revenue related to mutual assistance, administrative charges, off-system sales, and late payment charges. Other revenues decreased for the three and six months ended June 30, 2020, compared to the same period in 2019, as BGE temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored service to customers upon request who were disconnected in the last twelve months.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries but impact Operating revenues related to supplied electricity and natural gas. Drivers of Operating revenues related to commodity procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. BGE recovers electricity, natural gas and procurement costs from customers with a slight mark-up.

See Note 4 — Segment Information of the Combined Notes to the Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

The decrease of $14 million and decrease of $87 million for the three and six months ended June 30, 2020 compared to the same period in 2019, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

167

BGE

The changes in Operating and maintenance expense consisted of the following:

	Three Months Ended June 30, 2020			Six Months Ended June 30, 2020
	Increase (Decrease)			Increase (Decrease)
Credit loss expense	$	7		$	6
BSC costs	1			4
Labor, other benefits, contracting and materials	1			3
Storm-related costs	—			(5		)
Pension and non-pension postretirement benefits expense	(1		)	(1		)
Other	(2		)	(2		)
	6			5
Regulatory required programs	(1		)	(1		)
Total increase	$	5		$	4

The changes in Depreciation and amortization expense consisted of the following:

	Three Months Ended June 30, 2020		Six Months Ended June 30, 2020
	Increase		Increase (Decrease)
Depreciation and amortization(a)	$	9	$	21
Regulatory required programs	3		(1		)
Total increase	$	12	$	20

_________

(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were (129.4)% and 19.6% for the three months ended June 30, 2020 and 2019, respectively, and 7.6% and 18.6% for the six months ended June 30, 2020 and 2019. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters and Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

168

PHI

Results of Operations — PHI

PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. See the Results of Operations for Pepco, DPL and ACE for additional information.

	Three Months Ended June 30,					(Unfavorable)Favorable Variance			Six Months Ended June 30,						(Unfavorable)Favorable Variance
	2020		2019						2020			2019
PHI	$	94	$	106		$	(12	)	$	202		$	223		$	(21	)
Pepco	57		64			(7		)	109			119			(10		)
DPL	19		30			(11		)	64			83			(19		)
ACE	18		14			4			31			24			7
Other(a)	—		(2		)	2			(2		)	(3		)	1

_________

(a) Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities and other financing and investing activities.

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net Income decreased by $12 million primarily due to an increase in credit loss expense including the impacts of COVID-19 and an increase in various expenses, partially offset by higher electric distribution rates primarily at ACE.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net Income decreased by $21 million primarily due to an increase in credit loss expense including the impacts of COVID-19, unfavorable weather conditions in ACE's service territory and an increase in various expenses, partially offset by higher electric distribution rates primarily at ACE.

169

Pepco

Results of Operations — Pepco

	Three Months Ended June 30,						(Unfavorable) Favorable Variance			Six Months Ended June 30,						(Unfavorable) Favorable Variance
	2020			2019						2020			2019
Operating revenues	$	494		$	531		$	(37	)	$	1,039		$	1,106		$	(67	)
Operating expenses
Purchased power expense	138			144			6			303			331			28
Operating and maintenance	119			111			(8		)	231			230			(1		)
Depreciation and amortization	92			93			1			186			186			—
Taxes other than income taxes	87			90			3			179			182			3
Total operating expenses	436			438			2			899			929			30
Operating income	58			93			(35		)	140			177			(37		)
Other income and (deductions)
Interest expense, net	(34		)	(34		)	—			(68		)	(68		)	—
Other, net	9			7			2			18			14			4
Total other income and (deductions)	(25		)	(27		)	2			(50		)	(54		)	4
Income before income taxes	33			66			(33		)	90			123			(33		)
Income taxes	(24		)	2			26			(19		)	4			23
Net income	$	57		$	64		$	(7	)	$	109		$	119		$	(10	)

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income decreased by $7 million primarily due to an increase in credit loss expense including the impacts of COVID-19.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income decreased by $10 million primarily due to an increase in credit loss expense including the impacts of COVID-19.

The changes in Operating revenues consisted of the following:

	Three Months Ended June 30, 2020			Six Months Ended June 30, 2020
	Increase (Decrease)			Increase (Decrease)
Volume	$	2		$	4
Distribution	2			3
Transmission	(26		)	(28		)
Other	(1		)	(2		)
	(23		)	(23		)
Regulatory required programs	(14		)	(44		)
Total decrease	$	(37	)	$	(67	)

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

170

Pepco

Volume, exclusive of the effects of weather, remained relatively consistent for three and six months ended June 30, 2020 compared to the same period in 2019.

	As of June 30,
Number of Electric Customers	2020	2019
Residential	825,000	811,985
Small commercial & industrial	53,809	54,194
Large commercial & industrial	22,467	22,155
Public authorities & electric railroads	168	155
Total	901,444	888,489

Distribution Revenue increased for the three and six months ended June 30, 2020 compared to the same period in 2019, due to higher electric distribution rates in Maryland that became effective in August 2019.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenues decreased for the three and six months ended June 30, 2020 compared to the same period in 2019, primarily due to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of other taxes. Other revenue decreased for the three and six months ended June 30, 2020, compared to the same period in 2019, as Pepco temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored services to customers upon request who were disconnected in the last twelve months.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to commodity and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.

See Note 4 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

The decrease of $6 million and $28 million for the three and six months ended June 30, 2020 compared to the same period 2019, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

171

Pepco

The changes in Operating and maintenance expense consisted of the following:

	Three Months Ended June 30, 2020			Six Months Ended June 30, 2020
	Increase (Decrease)			Increase (Decrease)
Labor, other benefits, contracting and materials	$	5		$	12
Credit loss expense	8			7
Storm-related costs	1			(1		)
Pension and non-pension postretirement benefits expense	(1		)	(3		)
BSC and PHISCO costs	—			(3		)
Expiration of lease arrangement	(4		)	(8		)
Other	(3		)	(4		)
	6			—
Regulatory required programs	2			1
Total increase	$	8		$	1

The changes in Depreciation and amortization expense consisted of the following:

	Three Months Ended June 30, 2020			Six Months Ended June 30, 2020
	Increase (Decrease)			Increase (Decrease)
Depreciation and amortization(a)	$	4		$	9
Regulatory required programs	(5		)	(9		)
Total decrease	$	(1	)	$	—

_________

(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were (72.7)% and 3.0% for the three months ended June 30, 2020 and 2019, respectively, and (21.1)% and 3.3% for the six months ended June 30, 2020 and 2019, respectively. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters and Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

172

DPL

Results of Operations — DPL

	Three Months Ended June 30,						(Unfavorable)Favorable Variance			Six Months Ended June 30,						(Unfavorable)Favorable Variance
	2020			2019						2020			2019
Operating revenues	$	267		$	287		$	(20	)	$	617		$	667		$	(50	)
Operating expenses
Purchased power and fuel expense	107			107			—			249			271			22
Operating and maintenance	92			77			(15		)	172			160			(12		)
Depreciation and amortization	47			45			(2		)	94			91			(3		)
Taxes other than income taxes	17			14			(3		)	32			28			(4		)
Total operating expenses	263			243			(20		)	547			550			3
Operating income	4			44			(40		)	70			117			(47		)
Other income and (deductions)
Interest expense, net	(15		)	(15		)	—			(31		)	(30		)	(1		)
Other, net	2			5			(3		)	5			7			(2		)
Total other income and (deductions)	(13		)	(10		)	(3		)	(26		)	(23		)	(3		)
(Loss) income before income taxes	(9		)	34			(43		)	44			94			(50		)
Income taxes	(28		)	4			32			(20		)	11			31
Net income	$	19		$	30		$	(11	)	$	64		$	83		$	(19	)

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income decreased by $11 million primarily due to an increase in credit loss expense including the impacts of COVID-19 and an increase in various expenses, partially offset by favorable weather conditions in DPL's Delaware service territory.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income decreased by $19 million primarily due to an increase in credit loss expense including the impacts of COVID-19 and an increase in various expenses.

The changes in Operating revenues consisted of the following:

	Three Months Ended June 30, 2020									Six Months Ended June 30, 2020
	Increase (Decrease)									Increase (Decrease)
	Electric			Gas			Total			Electric			Gas			Total
Weather	$	1		$	6		$	7		$	(5	)	$	—		$	(5	)
Volume	—			(3		)	(3		)	1			(3		)	(2		)
Distribution	—			—			—			2			3			5
Transmission	(25		)	—			(25		)	(22		)	—			(22		)
Other	(1		)	—			(1		)	(2		)	(1		)	(3		)
	(25		)	3			(22		)	(26		)	(1		)	(27		)
Regulatory required programs	(1		)	3			2			(22		)	(1		)	(23		)
Total (decrease) increase	$	(26	)	$	6		$	(20	)	$	(48	)	$	(2	)	$	(50	)

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

173

DPL

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended June 30, 2020 compared to the same period in 2019, Operating revenues related to weather increased due to the impact of favorable weather conditions in DPL's Delaware service territory. During the six months ended June 30, 2020 compared to the same period in 2019, Operating revenues related to weather decreased due to the impact of unfavorable weather conditions in DPL's Delaware service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the three and six months ended June 30, 2020 compared to same period in 2019 and normal weather consisted of the following:

Delaware Electric Service Territory				% Change
Three Months Ended June 30,	2020	2019	Normal	2020 vs. 2019		2020 vs. Normal
Heating Degree-Days	606	300	467	102.0	%	29.8	%
Cooling Degree-Days	299	386	334	(22.5	)%	(10.5	)%
				% Change
Six Months Ended June 30,	2020	2019	Normal	2020 vs. 2019		2020 vs. Normal
Heating Degree-Days	2,609	2,822	2,980	(7.5	)%	(12.4	)%
Cooling Degree-Days	299	386	335	(22.5	)%	(10.7	)%

Delaware Natural Gas Service Territory				% Change
Three Months Ended June 30,	2020	2019	Normal	2020 vs. 2019		2020 vs. Normal
Heating Degree-Days	606	300	486	102.0	%	24.7	%
				% Change
Six Months Ended June 30,	2020	2019	Normal	2020 vs. 2019		2020 vs. Normal
Heating Degree-Days	2,609	2,822	2,984	(7.5	)%	(12.6	)%

Volume, exclusive of the effects of weather, remained relatively consistent for the three and six months ended June 30, 2020 compared to the same period in 2019.

Electric Retail Deliveries to Delaware Customers (in GWhs)	Three Months Ended June 30,		% Change		Weather - Normal % Change(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change(b)
	2020	2019					2020	2019
Residential	703	652	7.8	%	4.6	%	1,446	1,503	(3.8	)%	1.4	%
Small commercial & industrial	274	306	(10.5	)%	(10.9	)%	570	626	(8.9	)%	(6.4	)%
Large commercial & industrial	810	866	(6.5	)%	(6.1	)%	1,633	1,676	(2.6	)%	(1.7	)%
Public authorities & electric railroads	9	9	—	%	4.0	%	17	17	—	%	3.0	%
Total electric retail deliveries(a)	1,796	1,833	(2.0	)%	(3.0	)%	3,666	3,822	(4.1	)%	(1.2	)%

174

DPL

	As of June 30,
Number of Total Electric Customers (Maryland and Delaware)	2020	2019
Residential	470,788	465,423
Small commercial & industrial	61,958	61,552
Large commercial & industrial	1,402	1,398
Public authorities & electric railroads	612	619
Total	534,760	528,992

_________

(a) Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.

Natural Gas Retail Deliveries to Delaware Customers (in mmcf)	Three Months Ended June 30,		% Change		Weather - Normal % Change(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change(b)
	2020	2019					2020	2019
Residential	1,168	741	57.6	%	(11.8	)%	4,815	5,348	(10.0	)%	(2.8	)%
Small commercial & industrial	557	566	(1.6	)%	(35.0	)%	2,228	2,586	(13.8	)%	(7.4	)%
Large commercial & industrial	411	442	(7.0	)%	(7.0	)%	863	965	(10.6	)%	(10.6	)%
Transportation	1,472	1,475	(0.2	)%	(8.0	)%	3,580	3,693	(3.1	)%	(0.9	)%
Total natural gas deliveries(a)	3,608	3,224	11.9	%	(14.1	)%	11,486	12,592	(8.8	)%	(3.8	)%

	As of June 30,
Number of Delaware Natural Gas Customers	2020	2019
Residential	126,245	124,325
Small commercial & industrial	9,914	9,907
Large commercial & industrial	17	18
Transportation	159	158
Total	136,335	134,408

__________

(a) Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.

(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Distribution Revenue increased for the six months ended June 30, 2020 compared to the same period in 2019 primarily due to higher natural gas distribution rates due to the Gas Distribution System Improvement Charge (DSIC) fully implemented in the first quarter of 2020.

Transmission Revenues. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar years. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the three and six months ended June 30, 2020 compared to the same period in 2019 primarily due to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of other taxes. Other revenue decreased for the three and six months ended June 30, 2020 compared to the same period in 2019, as DPL temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored service to customers upon request who were disconnected in the last twelve months.

175

DPL

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to commodity and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up and natural gas costs from customers without mark-up.

See Note 4 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

The decrease of $22 million for the six months ended June 30, 2020 compared to the same period in 2019 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

The changes in Operating and maintenance expense consisted of the following:

	Three Months Ended June 30, 2020			Six Months Ended June 30, 2020
	Increase (Decrease)			Increase (Decrease)
Labor, other benefits, contracting and materials	$	8		$	8
Credit loss expense	7			5
Storm-related costs	2			2
Pension and non-pension postretirement benefits expense	(1		)	(2		)
BSC and PHISCO costs	—			(2		)
Other	(5		)	(2		)
	11			9
Regulatory required programs	4			3
Total increase	$	15		$	12

The changes in Depreciation and amortization expense consisted of the following:

	Three Months Ended June 30, 2020			Six Months Ended June 30, 2020
	Increase (Decrease)			Increase (Decrease)
Depreciation and amortization(a)	$	3		$	5
Regulatory required programs	(1		)	(2		)
Total increase	$	2		$	3

_________

(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were 311.1% and 11.8% for the three months ended June 30, 2020 and 2019, respectively, and (45.5)% and 11.7% for the six months ended June 30, 2020 and 2019, respectively. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters and Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

176

ACE

Results of Operations — ACE

	Three Months Ended June 30,						(Unfavorable) Favorable Variance			Six Months Ended June 30,						(Unfavorable) Favorable Variance
	2020			2019						2020			2019
Operating revenues	$	256		$	274		$	(18	)	$	532		$	547		$	(15	)
Operating expenses
Purchased power expense	130			131			1			259			270			11
Operating and maintenance	82			74			(8		)	160			155			(5		)
Depreciation and amortization	44			40			(4		)	86			71			(15		)
Taxes other than income taxes	2			1			(1		)	4			2			(2		)
Total operating expenses	258			246			(12		)	509			498			(11		)
Gain on sale of assets	—			—			—			2			—			2
Operating (loss) income	(2		)	28			(30		)	25			49			(24		)
Other income and (deductions)
Interest expense, net	(15		)	(15		)	—			(29		)	(28		)	(1		)
Other, net	2			1			1			3			4			(1		)
Total other income and (deductions)	(13		)	(14		)	1			(26		)	(24		)	(2		)
Income before income taxes	(15		)	14			(29		)	(1		)	25			(26		)
Income taxes	(33		)	—			33			(32		)	1			33
Net income	$	18		$	14		$	4		$	31		$	24		$	7

Three Months Ended June 30, 2020 Compared to Three Months Ended June 30, 2019. Net income increased by $4 million primarily due to higher electric distribution rates that became effective in April 2020 partially offset by lower commercial and industrial usage.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019. Net income increased by $7 million primarily due to higher electric distribution rates that became effective in April 2019 and April 2020, partially offset by unfavorable weather conditions in ACE’s service territory, lower commercial and industrial usage and increased depreciation and amortization expense.

The changes in Operating revenues consisted of the following:

	Three Months Ended June 30, 2020			Six Months Ended June 30, 2020
	(Decrease) Increase			(Decrease) Increase
Weather	$	(1	)	$	(5	)
Volume	(4		)	(6		)
Distribution	5			20
Transmission	(24		)	(18		)
Other	(1		)	(2		)
	(25		)	(11		)
Regulatory required programs	7			(4		)
Total decrease	$	(18	)	$	(15	)

Weather. The demand for electricity is affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. There was a decrease related to weather for the six months ended June 30, 2020 compared to same period in 2019 due to the impact of unfavorable weather conditions in ACE's service territory.

177

ACE

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the three and six months ended June 30, 2020 compared to same period in 2019 consisted of the following:

Heating and Cooling Degree-Days			Normal	% Change
Three Months Ended June 30,	2020	2019		2020 vs. 2019		2020 vs. Normal
Heating Degree-Days	613	380	541	61.3	%	13.3	%
Cooling Degree-Days	312	351	304	(11.1	)%	2.6	%
			Normal	% Change
Six Months Ended June 30,	2020	2019		2020 vs. 2019		2020 vs. Normal
Heating Degree-Days	2,561	2,886	3,034	(11.3	)%	(15.6	)%
Cooling Degree-Days	312	351	305	(11.1	)%	2.3	%

Volume, exclusive of the effects of weather, decreased for the three and six months ended June 30, 2020 compared to the same period in 2019, primarily due to lower commercial and industrial usage.

Electric Retail Deliveries to Customers (in GWhs)	Three Months Ended June 30,		% Change		Weather - Normal % Change(b)		Six Months Ended June 30, 2020		% Change		Weather - Normal % Change(b)
	2020	2019					2020	2019
Residential	850	804	5.7	%	6.5	%	1,660	1,713	(3.1	)%	1.3	%
Small commercial & industrial	276	314	(12.1	)%	(12.8	)%	570	624	(8.7	)%	(6.4	)%
Large commercial & industrial	702	872	(19.5	)%	(19.3	)%	1,437	1,662	(13.5	)%	(12.7	)%
Public authorities & electric railroads	11	11	—	%	2.8	%	24	24	—	%	(0.9	)%
Total electric retail deliveries(a)	1,839	2,001	(8.1	)%	(7.9	)%	3,691	4,023	(8.3	)%	(5.7	)%

	As of June 30,
Number of Electric Customers	2020	2019
Residential	496,668	492,940
Small commercial & industrial	61,468	61,416
Large commercial & industrial	3,327	3,464
Public authorities & electric railroads	687	672
Total	562,150	558,492

_________

(a) Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.

Distribution Revenue increased for the three and six months ended June 30, 2020 compared to the same period in 2019 primarily due to higher electric distribution rates that became effective in April 2019 and April 2020.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the three and six months ended June 30, 2020 compared to the same period in 2019, primarily due to settlement agreement for

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ACE

ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to commodity, REC and ZEC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power expense. ACE recovers electricity, REC and ZEC procurement costs from customers without mark-up.

See Note 4 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.

The decrease of $1 million and $11 million for three and six months ended June 30, 2020 compared to the same period in 2019 , respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

The changes in Operating and maintenance expense consisted of the following:

	Three Months Ended June 30, 2020			Six Months Ended June 30, 2020
	Increase (Decrease)			Increase (Decrease)
Labor, other benefits, contracting and materials	$	6		$	9
Storm-related costs	(1		)	(1		)
BSC and PHISCO costs	—			(1		)
Credit loss expense(a)	7			6
Other	(3		)	(8		)
	9			5
Regulatory required programs	(1		)	—
Total increase	$	8		$	5

_________

(a) ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues.

The changes in Depreciation and amortization expense consisted of the following:

	Three Months Ended June 30, 2020			Six Months Ended June 30, 2020
	Increase (Decrease)			Increase (Decrease)
Depreciation and amortization(a)	$	3		$	12
Regulatory asset amortization	(2		)	(1		)
Regulatory required programs	3			4
Total increase	$	4		$	15

_________

(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.

Gain on sale of assets for the six months ended June 30, 2020 compared to the same period in 2019 increased due to the sale of land in February 2020.

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ACE

Effective income tax rates were 220.0% and 0.0% for the three months ended June 30, 2020 and 2019, respectively, 3,200.0% and 4.0% for the six months ended June 30, 2020 and 2019, respectively. The change is primarily related to the settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 2 — Regulatory Matters and Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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Liquidity and Capital Resources

All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, the sale of certain receivables, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $10.7 billion. As a result of disruptions in the commercial paper markets due to COVID-19 in March of 2020, Generation borrowed $1.5 billion on its revolving credit facility to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020 using funds from short-term loans issued in March 2020, cash proceeds from the sale of certain customer accounts receivable, and borrowings from the Exelon intercompany money pool. See Note 5 - Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sale of customer accounts receivable. Exelon Corporate, Generation, and the Utility Registrants continued to issue commercial paper during the second quarter of 2020. See Executive Overview for additional information on COVID-19. The Registrants continue to utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.

The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

Despite disruptions in the financial markets due to COVID-19, the Registrants have been able to fund their liquidity needs to date. As of December 31, 2019, Exelon had approximately $4.0 billion of long-term debt that matures in 2020, excluding project financings and floating rate long-term debt. Of this, as of June 30, 2020, Exelon has redeemed or refinanced approximately $3.4 billion that is maturing in 2020. The remaining amount of $0.6 billion on Exelon’s and Generation’s Consolidated Balance Sheet matures in the fourth quarter of 2020. To date in 2020, the Registrants have been able to execute their expected debt issuances and have issued long-term debt of $5.1 billion, of which $4.0 billion was issued in the period of April to July of 2020. The Registrants accelerated the timing of a number of planned debt issuances resulting in the $4.0 billion issued in the period of April to July of 2020 and the Registrants have now completed their planned long-term debt issuances for the 2020 year.

NRC Minimum Funding Requirements (Exelon and Generation)

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 7 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

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If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value. A shortfall could require that Generation address the shortfall by, among other things, obtaining a parental guarantee for Generation’s share of the funding assurance. However, the amount of any guarantees or other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. Upon issuance of any required financial guarantees, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, the NRC must approve an exemption in order for the plant’s owner(s) to utilize the NDT fund to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by the owner(s) without reimbursement from or access to the NDT funds. The ultimate costs for spent fuel management may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the DOE reimbursement agreements.

As of June 30, 2020, Exelon would not be required to post a parental guarantee for TMI Unit 1 under the SAFSTOR scenario which is the planned decommissioning option as described in the TMI Unit 1 PSDAR filed by Generation with the NRC on April 5, 2019. On October 16, 2019, the NRC granted Generation's exemption request to use the TMI Unit 1 NDT funds for spent fuel management costs. An additional exemption request would be required to allow the funds to be spent on site restoration costs, which are not expected to be incurred in the near term.

Project Financing (Exelon and Generation)

Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities. See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt. Refer to Note 16 — Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on credit facilities.

Cash Flows from Operating Activities (All Registrants)

General

Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers and the sale of certain receivables.

The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions.

See Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2019 Form 10-K for additional information of regulatory and legal proceedings and proposed legislation.

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The following table provides a summary of the change in cash flows from operating activities for the six months ended June 30, 2020 and 2019 by Registrant:

(Decrease) increase in cash flows from operating activities	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Net income	$	(510	)	$	(172	)	$	(237	)	$	(92	)	$	13		$	(21	)	$	(10	)	$	(19	)	$	7
Adjustments to reconcile net income to cash:
Non-cash operating activities	305			44			315			17			4			(7		)	(29		)	18			10
Pension and non-pension postretirement benefit contributions	(203		)	(85		)	(76		)	9			(26		)	(20		)	—			1			(2		)
Income taxes	(265		)	(295		)	(133		)	26			55			(18		)	5			(23		)	(4		)
Changes in working capital and other noncurrent assets and liabilities	(46		)	(149		)	(24		)	115			1			(6		)	12			5			(14		)
Option premiums paid, net	(150		)	(150		)	—			—			—			—			—			—			—
Collateral posted, net	651			660			(14		)	—			5			—			—			—			—
(Decrease) increase in cash flows from operating activities	$	(218	)	$	(147	)	$	(169	)	$	75		$	52		$	(72	)	$	(22	)	$	(18	)	$	(3	)

Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for the Registrants for the six months ended June 30, 2020 and 2019 were as follows:

• See Note 17 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statement of Cash Flows for additional information on non-cash operating activity.

• See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statement of Cash Flows for additional information on income taxes.

• Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the OTC markets.

• During 2020, Exelon and Generation derecognized approximately $1.2 billion of accounts receivable. See Note 5 — Accounts Receivable for additional information on the sales of customer accounts receivable.

Cash Flows from Investing Activities (All Registrants)

The following table provides a summary of the change in cash flows from investing activities for the six months ended June 30, 2020 and 2019 by Registrant:

Increase (decrease) in cash flows from investing activities	Exelon			Generation			ComEd			PECO			BGE			PHI		Pepco			DPL			ACE
Capital expenditures	$	(201	)	$	(40	)	$	(68	)	$	(65	)	$	(6	)	$	12	$	(26	)	$	(24	)	$	49
Proceeds from NDT fund sales, net	(125		)	(125		)	—			—			—			—		—			—			—
Proceeds from sales of assets and businesses	(14		)	(14		)	—			—			—			—		—			—			—
Changes in intercompany money pool	—			179			—			68			—			—		38			(55		)	—
Collection of DPP	1,102			1,102			—			—			—			—		—			—			—
Other investing activities	(22		)	(2		)	(21		)	(1		)	(8		)	—		(4		)	(4		)	5
Increase (decrease) in cash flows from investing activities	$	740		$	1,100		$	(89	)	$	2		$	(14	)	$	12	$	8		$	(83	)	$	54

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Significant investing cash flow impacts for the Registrants for six months ended June 30, 2020 and 2019 were as follows:

• Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer below for additional information on projected capital expenditure spending.

• Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

Capital Expenditure Spending

As of June 30, 2020, the most recent estimates of capital expenditures for plant additions and improvements for 2020 are as follows:

(in millions)	Transmission	Distribution	Gas	Total
Exelon	N/A	N/A	N/A	$	8,075
Generation	N/A	N/A	N/A	1,500
ComEd	450	1,900	N/A	2,350
PECO	125	725	300	1,150
BGE	300	550	450	1,300
PHI	450	1,125	100	1,675
Pepco	150	700	N/A	850
DPL	125	225	100	450
ACE	175	200	N/A	375

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Cash Flows from Financing Activities (All Registrants)

The following table provides a summary of the change in cash flows from financing activities for the six months ended June 30, 2020 and 2019 by Registrant:

Increase (decrease) in cash flows from financing activities	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Changes in short-term borrowings, net	$	(596	)	$	280		$	(433	)	$	—		$	(270	)	$	(37	)	$	(28	)	$	(56	)	$	47
Long-term debt, net	2,356			(443		)	900			350			400			53			6			99			(52		)
Changes in intercompany money pool	—			100			—			(52		)	—			7			50			(38		)	5
Dividends paid on common stock	(42		)	—			5			10			(11		)	—			(29		)	4			(11		)
Distributions to member	—			(488		)	—			—			—			(52		)	—			—			—
Contributions from parent/member	—			—			125			86			26			76			8			106			(39		)
Other financing activities	(79		)	(9		)	(4		)	(2		)	(8		)	(4		)	(3		)	(1		)	—
Increase (decrease) in cash flows from financing activities	$	1,639		$	(560	)	$	593		$	392		$	137		$	43		$	4		$	114		$	(50	)

Significant financing cash flow impacts for the Registrants for the six months ended June 30, 2020 and 2019 were as follows:

• Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to 12 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on short-term borrowings.

• Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to 12 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on debt issuances. Refer to debt redemptions tables below for more information.

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• Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

• Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2019 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.

• For the six months ended June 30, 2020, other financing activities primarily consists of debt issuance costs. See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants��� debt issuances.

Debt

See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

During the six months ended June 30, 2020, the following long-term debt was retired and/or redeemed:

Company(a)	Type	Interest Rate		Maturity	Amount
Exelon	Notes	2.85	%	June 15, 2020	$	900
Exelon	Long-Term Software License Agreement	3.95	%	May 1, 2024	24
Generation	Senior Notes	2.95	%	January 15, 2020	1,000
Generation	Tax-Exempt Bonds	2.50% - 2.70%		December 1, 2025 - June 1, 2036	379
Generation	ExGen Renewables IV Nonrecourse Debt(b)	3mL +3%		November 30, 2024	22
Generation	Continental Wind Nonrecourse Debt(b)	6.00	%	February 28, 2033	18
Generation	Antelope Valley DOE Nonrecourse Debt(b)	2.29% - 3.56%		January 5, 2037	7
Generation	Energy Efficiency Project Financing	3.71	%	December 31, 2020	4
Generation	Renewable Power Generation Nonrecourse Debt(b)	4.11	%	March 31, 2035	3
Generation	SolGen Nonrecourse Debt	3.93	%	September 30, 2036	2
Generation	Energy Efficiency Project Financing	4.12	%	November 30, 2020	1
ACE	Tax-Exempt First Mortgage Bonds	4.88	%	June 1, 2029	23
ACE	Transition Bonds	5.55	%	October 20, 2023	9

_________

(a) On July 1, Generation redeemed $550 million of 4.00% senior notes. On August 3, 2020, ComEd redeemed $500 million of first mortgage bonds, and DPL redeemed $78 million of tax-exempt bonds.

(b) See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the six months ended June 30, 2020 and for the third quarter of 2020 were as follows:

Period	Declaration Date	Shareholder of Record Date	Dividend Payable Date	Cash per Share(a)
First Quarter 2020	January 28, 2020	February 20, 2020	March 10, 2020	$	0.3825
Second Quarter 2020	April 28, 2020	May 15, 2020	June 10, 2020	$	0.3825
Third Quarter 2020	July 28, 2020	August 14, 2020	September 10, 2020	$	0.3825

_________

(a) Exelon's Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020.

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Credit Matters (All Registrants)

The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include $10.7 billion in aggregate total commitments of which $8.6 billion was available to support additional commercial paper as of June 30, 2020, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the second quarter of 2020 to fund their short-term liquidity needs. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PART I. ITEM 1A. RISK FACTORS of the Exelon 2019 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flow from operating activities, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of June 30, 2020, it would have been required to provide incremental collateral of $1.3 billion to meet collateral obligations for derivatives, non-derivatives, normal purchases and normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within the $5 billion of available credit capacity of its revolver.

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at June 30, 2020 and available credit facility capacity prior to any incremental collateral at June 30, 2020:

	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	4	$	—	$	998
PECO	—		24		600
BGE	11		26		600
Pepco	11		—		285
DPL	4		10		300
ACE	—		—		295

_________

(a) Represents incremental collateral related to natural gas procurement contracts.

Exelon Credit Facilities

Exelon Corporate, ComEd and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ short-term borrowing activity. See Note 16 — Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on the Registrants’ credit facilities.

Security Ratings

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The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.

The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The Registrants’ credit ratings did not change for the six months ended June 30, 2020. On July 21, 2020, S&P lowered ComEd's long-term issuer credit rating from 'A-' to a 'BBB+'. S&P also affirmed the current 'A' rating on ComEd's senior secured debt and 'A-2' short-term rating, which influences long and short-term borrowing cost.

Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of June 30, 2020, are presented in the following table:

Exelon Intercompany Money Pool	During the Three Months Ended June 30, 2020					As of June 30, 2020
Contributed (Borrowed)	Maximum Contributed		Maximum Borrowed			Contributed (Borrowed)
Exelon Corporate	$	1,364	$	—		$	372
Generation	—		(980		)	—
BSC	—		(504		)	(410		)
PHI Corporate	—		(22		)	(22		)
PCI	60		—			60

PHI Intercompany Money Pool	During the Three Months Ended June 30, 2020					As of June 30, 2020
Contributed (Borrowed)	Maximum Contributed		Maximum Borrowed			Contributed (Borrowed)
Pepco	$	126	$	(57	)	$	(50	)
DPL	62		(49		)	55
ACE	—		(77		)	(5		)

Shelf Registration Statements

Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2022. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

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Regulatory Authorizations

ComEd, PECO, BGE, Pepco, DPL and ACE are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

	As of June 30, 2020
	Short-term Financing Authority(a)				Remaining Long-term Financing Authority(a)
	Commission	Expiration Date	Amount		Commission	Expiration Date	Amount
ComEd	FERC	December 31, 2021	$	2,500	ICC	February 1, 2023	$	893
PECO	FERC	December 31, 2021	1,500		PAPUC	December 31, 2021	1,225
BGE	FERC	December 31, 2021	700		MDPSC	N/A	1,100
Pepco	FERC	December 31, 2021	500		MDPSC / DCPSC	December 31, 2022	1,050
DPL	FERC	December 31, 2021	500		MDPSC / DPSC	December 31, 2022	375
ACE	NJBPU	December 31, 2021	350		NJBPU	December 31, 2020	77

_________

(a) Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.

Contractual Obligations and Off-Balance Sheet Arrangements

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 2019 Form 10-K.

Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements in the Exelon 2019 Form 10-K for additional information.

For an in-depth discussion of the Registrants' contractual obligations and off-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in the Exelon 2019 Form 10-K. In addition, see discussion of off-balance sheet arrangement discussed below.

Sales of Customer Accounts Receivable

On April 8, 2020, Generation entered into an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain receivables, which expires on April 7, 2021 unless renewed by the mutual consent of the parties in accordance with its terms. The facility allows Generation to obtain financing at lower cost and diversify its sources of liquidity. See Note 5 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.

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Item 3.    Quantitative and Qualitative Disclosures about Market Risk

The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates and equity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities. The following discussion serves as an update to ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of Exelon’s 2019 Annual Report on Form 10-K incorporated herein by reference.

Commodity Price Risk (All Registrants)

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies and other factors. To the extent the total amount of energy Exelon generates and purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel and other commodities.

Generation

Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards and options, with approved counterparties to hedge anticipated exposures. Generation uses derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 2020 through 2022.

As of June 30, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 98%-101% and 76%-79% for 2020 and 2021, respectively. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on June 30, 2020 market conditions and hedged position would be an increase in pre-tax net income of approximately $25 million for 2020 and a decrease of $189 million for 2021. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Fuel Procurement

Approximately 60% of Generation’s uranium concentrate requirements from 2020 through 2024 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s financial statements.

Utility Registrants

There have been no significant changes or additions to the Utility Registrants exposures to commodity price risk that were described in ITEM 1A. RISK FACTORS of Exelon’s 2019 Annual Report on Form 10-K. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding commodity price risk exposure.

Trading and Non-Trading Marketing Activities

The following table detailing Exelon’s, Generation’s and ComEd’s trading and non-trading marketing activities are included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

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The following table provides detail on changes in Exelon’s, Generation’s and ComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, 2019 to June 30, 2020. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all NPNS contracts and does not segregate proprietary trading activity. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of June 30, 2020 and December 31, 2019.

	Exelon			Generation			ComEd
Total mark-to-market energy contract net assets (liabilities) at December 31, 2019(a)	$	567		$	868		$	(301	)
Total change in fair value during 2020 of contracts recorded in results of operations	(182		)	(182		)	—
Reclassification to realized at settlement of contracts recorded in results of operations	385			385			—
Changes in fair value — recorded through regulatory assets(b)	(17		)	—			(17		)
Changes in allocated collateral	(353		)	(353		)	—
Net option premium paid	102			102			—
Option premium amortization	(27		)	(27		)	—
Upfront payments and amortizations(c)	(50		)	(50		)	—
Total mark-to-market energy contract net assets (liabilities) at June 30, 2020(a)	$	425		$	743		$	(318	)

_________

(a) Amounts are shown net of collateral paid to and received from counterparties.

(b) For ComEd, the changes in fair value are recorded as a change in regulatory assets. As of June 30, 2020, ComEd recorded a regulatory asset of $318 million related to its mark-to-market derivative liabilities with unaffiliated suppliers. For the six months ended June 30, 2020, ComEd recorded $35 million of decreases in fair value and an increase for realized losses due to settlements of $18 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.

(c) Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.

Fair Values

The following tables present maturity and source of fair value for Exelon, Generation and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 13 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

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Exelon

	Maturities Within																	Total Fair Value
	2020			2021			2022			2023		2024			2025 and Beyond
Normal Operations, Commodity derivative contracts(a)(b):
Actively quoted prices (Level 1)	$	(72	)	$	(11	)	$	(20	)	$	1	$	6		$	17		$	(79	)
Prices provided by external sources (Level 2)	77			35			37			13		—			1			163
Prices based on model or other valuation methods (Level 3)(c)	203			223			83			3		(12		)	(159		)	341
Total	$	208		$	247		$	100		$	17	$	(6	)	$	(141	)	$	425

_________

(a) Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.

(b) Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $576 million at June 30, 2020.

(c) Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

Generation

	Maturities Within															Total Fair Value
	2020			2021			2022			2023		2024		2025 and Beyond
Normal Operations, Commodity derivative contracts(a)(b):
Actively quoted prices (Level 1)	$	(72	)	$	(11	)	$	(20	)	$	1	$	6	$	17	$	(79	)
Prices provided by external sources (Level 2)	77			35			37			13		—		1		163
Prices based on model or other valuation methods (Level 3)	220			252			112			32		16		27		659
Total	$	225		$	276		$	129		$	46	$	22	$	45	$	743

_________

(a) Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.

(b) Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $576 million at June 30, 2020.

ComEd

	Maturities Within																		Total Fair Value
	2020			2021			2022			2023			2024			2025 and Beyond
Commodity derivative contracts(a):
Prices based on model or other valuation methods (Level 3)(a)	$	(17	)	$	(29	)	$	(29	)	$	(29	)	$	(28	)	$	(186	)	$	(318	)

_________

(a) Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

Credit Risk (All Registrants)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the

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fair value of contracts at the reporting date. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for detailed discussion of credit risk.

Generation

The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchases and normal sales agreements, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2020. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs and commodity exchanges, which are discussed below.

Rating as of June 30, 2020	Total  Exposure Before Credit Collateral		Credit Collateral(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure		Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	772	$	25	$	747	$	1	$	117
Non-investment grade	35		26		9
No external ratings
Internally rated — investment grade	213		1		212
Internally rated — non-investment grade	130		17		113
Total	$	1,150	$	69	$	1,081	$	1	$	117

	Maturity of Credit Risk Exposure
Rating as of June 30, 2020	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	690	$	55	$	27	$	772
Non-investment grade	35		—		—		35
No external ratings
Internally rated — investment grade	156		32		25		213
Internally rated — non-investment grade	118		6		6		130
Total	$	999	$	93	$	58	$	1,150

Net Credit Exposure by Type of Counterparty	As of June 30, 2020
Financial institutions	$	29
Investor-owned utilities, marketers, power producers	834
Energy cooperatives and municipalities	173
Other	45
Total	$	1,081

_________

(a) As of June 30, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $38 million of letters of credit.

The Utility Registrants

There have been no significant changes or additions to the Utility Registrants exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 2019 Annual Report on Form 10-K.

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See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding credit exposure to suppliers.

Credit-Risk-Related Contingent Features (All Registrants)

Generation

As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase of electricity, natural gas and other commodities. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.

Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s financial statements. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See Note 16 — Debt and Credit Agreements of Exelon’s 2019 Annual Report on Form 10-K for additional information.

Utility Registrants

As of June 30, 2020, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Exelon and Generation use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon and Generation may also utilize interest rate swaps to manage their interest rate exposure. A hypothetical 50 basis points increase in the interest rates associated with unhedged variable-rate debt (excluding commercial paper) and fixed-to-floating swaps would result in approximately a $2 million decrease in Exelon pre-tax income for the six months ended June 30, 2020. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Equity Price Risk (Exelon and Generation)

Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of June 30, 2020, Generation’s NDT funds are reflected at fair value in its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy. A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would result in a $696 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices.

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Item 4.    Controls and Procedures

During the second quarter of 2020, each of the Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to Exelon’s management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of June 30, 2020, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There were no changes in internal control over financial reporting during the second quarter of 2020 that materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting, including no changes resulting from COVID-19. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview for additional information on COVID-19.

PART II — OTHER INFORMATION

Item 1.    Legal Proceedings

The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s 2019 Form 10-K and (b) Notes 2 — Regulatory Matters and 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.

Item 1A.    Risk Factors

Risks Related to Exelon

At June 30, 2020, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2019 Form 10-K in ITEM 1A. RISK FACTORS, except for the following risk factors, which were added.

Our Results Could be Negatively Affected by the Impacts of COVID-19 (All Registrants).

The Registrants have taken steps to mitigate the potential risks posed by COVID-19. This is an evolving situation that could lead to extended disruption of economic activity in the Registrants’ respective markets. COVID-19 could negatively affect the Registrants’ ability to operate their respective generating and transmission and distribution assets, their ability to access capital markets, and results of operations. The Registrants cannot predict the extent of the impacts of COVID-19, which will depend on future developments and which are highly uncertain at this time. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview for additional information on COVID-19.

Exelon and ComEd have received requests for information related to an SEC investigation into their lobbying activities. The outcome of the investigation could have a material adverse effect on their reputation and consolidated financial statements (Exelon and ComEd).

On October 22, 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the State of Illinois. Exelon and ComEd have cooperated fully, including by providing all information

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requested by the SEC, and intend to continue to cooperate fully and expeditiously with the SEC. The outcome of the SEC’s investigation cannot be predicted and could subject Exelon and ComEd to criminal or civil penalties, sanctions or other remedial measures.  Any of the foregoing, as well as the appearance of non-compliance with anti-corruption and anti-bribery laws, could have an adverse impact on Exelon’s and ComEd’s reputations or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements. 

If ComEd violates its Deferred Prosecution Agreement announced on July 17, 2020, it could have an adverse effect on the reputation and consolidated financial statements of Exelon and ComEd (Exelon and ComEd).

On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and the investigation by the USAO into Exelon’s activities ends with no charges being brought against Exelon. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including, but not limited to, the following: (i) payment to the United States Treasury of $200 million, with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional $100 million within ninety days of such filing date; (ii) continued full cooperation with the government’s investigation; and (iii) ComEd’s adoption and maintenance of remedial measures involving compliance and reporting undertakings as specified in the DPA. If ComEd is found to have breached the terms of the DPA, the USAO may elect to prosecute, or bring a civil action against, ComEd for conduct alleged in the DPA or known to the government, which could result in fines or penalties and could have an adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements.

Item 4.    Mine Safety Disclosures

All Registrants

Not applicable to the Registrants.

Item 5.    Other Information

Amendments to Exelon, ComEd, PECO, BGE and PHI Governing Documents

On August 3, 2020, Exelon, ComEd, PECO, and BGE each adopted Amended and Restated Bylaws, and PHI entered into an Amended and Restated Limited Liability Company Agreement, to address certain administrative and other non-material matters. In addition, the amendments to each of the utilities’ governing documents provide that vacancies on the utilities’ respective boards of directors may only be filled by such utility’s shareholders and that the utilities’ respective governing documents may only be amended by such utility’s shareholders.

Item 6.    Exhibits

Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis and the relevant Registrant agrees to furnish a copy of any such instrument to the Commission upon request.

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Exhibit No.	Description
3.1*	Amended and Restated Bylaws of Exelon*
3.2*	Amended and Restated Bylaws of ComEd*
3.3*	Amended and Restated Bylaws of PECO*
3.4*	Amended and Restated Bylaws of BGE*
3.5*	Amended and Restated Limited Liability Company Agreement of PHI*
4.1	Exelon Generation Form of 3.250% Senior Notes due 2025 (File No. 333-85496, Form 8-K dated May 15, 2020, Exhibit 4.1).
4.2	One Hundred and Eighteenth Supplemental Indenture dated as of June 1, 2020 from PECO to U.S. Bank National Association, as trustee (File No. 000-16844, Form 8-K dated June 8, 2020, Exhibit 4.1).
4.3	BGE Form of 2.900% notes due June 15, 2050 (File No. 001-01910, Form 8-K dated June 5, 2020, Exhibit 4.2).
4.4	Pollution Control Facilities Loan Agreement, dated as of June 1, 2020, between The Pollution Control Financing Authority of Salem County and ACE (File No. 001-03559, Form 8-K dated June 2, 2020, Exhibit 4.1).
4.5	Supplemental Indenture, dated as of June 1, 2020, with respect to the ACE Mortgage and Deed of Trust, dated as of January 15, 1937 (File No. 001-03559, Form 8-K dated June 9, 2020, Exhibit 4.2).
4.6	Supplemental Indenture, dated as of June 1, 2020, with respect to the DPL Mortgage and Deed of Trust, dated as of October 1, 1943 (File No. 001-01405, Form 8-K dated June 9, 2020, Exhibit 4.4).
4.7	Gas Facilities Loan Agreement, dated as of July 1, 2020, between The Delaware Economic Development Authority and DPL (File No. 001-01405, Form 8-K dated July 1, 2020, Exhibit 4.1).
10.1*	Exelon Corporation Form of Non-Employee Directors’ Deferred Stock Unit Program Agreement.*
10.2	Exelon Corporation 2020 Long-Term Incentive Plan (Effective April 28, 2020) (File No. 001-16169, Proxy Statement filed March 18, 2020, Appendix A).
10.3*	Exelon Corporation 2020 Long-Term Incentive Plan Prospectus, dated May 27, 2020.*
10.4*	Form of Restricted Stock Unit Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan*
10.5*	Form of Performance Share Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan*
101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	Inline XBRL Taxonomy Extension Schema Document.
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document.

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101.LAB	Inline XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*Filed herewith

Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2020 filed by the following officers for the following companies:

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 Carim V. Khouzami 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 June 30, 2020 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 Carim V. Khouzami 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

198

SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON CORPORATION

/s/    CHRISTOPHER M. CRANE	/s/    JOSEPH NIGRO
Christopher M. Crane	Joseph Nigro
President and Chief Executive Officer (Principal Executive Officer) and Director	Senior Executive Vice President and Chief Financial Officer (Principal Financial Officer)
/s/    FABIAN E. SOUZA
Fabian E. Souza
Senior Vice President and Corporate Controller (Principal Accounting Officer)

August 4, 2020

199

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON GENERATION COMPANY, LLC

/s/    KENNETH W. CORNEW	/s/    BRYAN P. WRIGHT
Kenneth W. Cornew	Bryan P. Wright
President and Chief Executive Officer (Principal Executive Officer)	Senior Vice President and Chief Financial Officer (Principal Financial Officer)
/s/    MATTHEW N. BAUER
Matthew N. Bauer
Vice President and Controller (Principal Accounting Officer)

August 4, 2020

200

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

COMMONWEALTH EDISON COMPANY

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

August 4, 2020

201

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PECO ENERGY COMPANY

/s/    MICHAEL A. INNOCENZO	/s/    ROBERT J. STEFANI
Michael A. Innocenzo	Robert J. Stefani
President and Chief Executive Officer (Principal Executive Officer)	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/    CAROLINE FULGINITI
Caroline Fulginiti
Director, Accounting (Principal Accounting Officer)

August 4, 2020

202

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BALTIMORE GAS AND ELECTRIC COMPANY

/s/    CARIM V. KHOUZAMI	/s/    DAVID M. VAHOS
Carim V. Khouzami	David M. Vahos
Chief Executive Officer (Principal Executive Officer)	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/ JASON T. JONES
Jason T. Jones
Director, Accounting (Principal Accounting Officer)

August 4, 2020

203

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PEPCO HOLDINGS LLC

/s/ DAVID M. VELAZQUEZ	/s/    PHILLIP S. BARNETT
David M. Velazquez	Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting (Principal Accounting Officer)

August 4, 2020

204

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

POTOMAC ELECTRIC POWER COMPANY

/s/ DAVID M. VELAZQUEZ	/s/    PHILLIP S. BARNETT
David M. Velazquez	Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting (Principal Accounting Officer)

August 4, 2020

205

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DELMARVA POWER & LIGHT COMPANY

/s/ DAVID M. VELAZQUEZ	/s/    PHILLIP S. BARNETT
David M. Velazquez	Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting (Principal Accounting Officer)

August 4, 2020

206

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

ATLANTIC CITY ELECTRIC COMPANY

/s/ DAVID M. VELAZQUEZ	/s/    PHILLIP S. BARNETT
David M. Velazquez	Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting (Principal Accounting Officer)

August 4, 2020

207