EXELON CORP - Quarter Report: 2021 June (Form 10-Q)

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, 2021


☐ 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

Accelerated Filer

☐

Non-accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

Exelon Generation Company, LLC

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

Commonwealth Edison Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

PECO Energy Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

Baltimore Gas and Electric Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

Pepco Holdings LLC

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

Potomac Electric Power Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

Delmarva Power & Light Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

Atlantic City Electric Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

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, 2021 was:


Exelon Corporation Common Stock, without par value			977,832,660
Exelon Generation Company, LLC			not applicable
Commonwealth Edison Company Common Stock, $12.50 par value			127,021,380
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 Member's Equity	40


						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. Mergers, Acquisitions and Dispositions			57
			3. Regulatory Matters			58
			4. Revenue from Contracts with Customers			66
			5. Segment Information			69
			6. Accounts Receivable			84
			7. Early Plant Retirements			89
			8. Nuclear Decommissioning			93
			9. Asset Impairments			94
			10. Income Taxes			95
			11. Retirement Benefits			98
			12. Derivative Financial Instruments			100
			13. Debt and Credit Agreements			107
			14. Fair Value of Financial Assets and Liabilities			110
			15. Commitments and Contingencies			121
			16. Changes in Accumulated Other Comprehensive Income			130
			17. Variable Interest Entities			131
			18. Supplemental Financial Information			136
			19. Related Party Transactions			142
			20. Planned Separation			145


		Page No.


ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	146
	Exelon Corporation	146
	Executive Overview	146
	Financial Results of Operations	146
	Significant 2021 Transactions and Developments	151


	Other Key Business Drivers and Management Strategies	154
	Critical Accounting Policies and Estimates	156
	Results of Operations By Registrant	156
	Exelon Generation Company, LLC	157
	Commonwealth Edison Company	164
	PECO Energy Company	167
	Baltimore Gas and Electric Company	171
	Pepco Holdings LLC	174
	Potomac Electric Power Company	175
	Delmarva Power & Light Company	178
	Atlantic City Electric Company	182
	Liquidity and Capital Resources	185
	Contractual Obligations and Off-Balance Sheet Arrangements	193
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	194
ITEM 4.	CONTROLS AND PROCEDURES	198
PART II.	OTHER INFORMATION	199
ITEM 1.	LEGAL PROCEEDINGS	199
ITEM 1A.	RISK FACTORS	199
ITEM 4.	MINE SAFETY DISCLOSURES	199
ITEM 5.	OTHER INFORMATION	199
ITEM 6.	EXHIBITS	200
SIGNATURES		203
	Exelon Corporation	203
	Exelon Generation Company, LLC	204
	Commonwealth Edison Company	205
	PECO Energy Company	206
	Baltimore Gas and Electric Company	207
	Pepco Holdings LLC	208
	Potomac Electric Power Company	209
	Delmarva Power & Light Company	210
	Atlantic City Electric Company	211

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon						Exelon Corporation
Generation						Exelon Generation Company, LLC
ComEd						Commonwealth Edison Company
PECO						PECO Energy Company
BGE						Baltimore Gas and Electric Company
Pepco Holdings or PHI						Pepco Holdings LLC
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 Energy 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
RPG						Renewable Power Generation
SolGen						SolGen, LLC
TMI						Three Mile Island nuclear facility

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note - of the 2020 Form 10-K						Reference to specific Combined Note to Consolidated Financial Statements within Exelon's 2020 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						District of Columbia 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




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
GHG						Greenhouse Gas
GSA						Generation Supply Adjustment


IBEW						International Brotherhood of Electrical Workers
ICC						Illinois Commerce Commission
ICE						Intercontinental Exchange



IPA						Illinois Power Agency
IRC						Internal Revenue Code
IRS						Internal Revenue Service
ISO						Independent System Operator
ISO-NE						Independent System Operator New England Inc.

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
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

MPSC						Missouri Public Service Commission
MW						Megawatt
MWh						Megawatt hour


NAV						Net Asset Value
N/A						Not applicable
NDT						Nuclear Decommissioning Trust

NERC						North American Electric Reliability Corporation
NGX						Natural Gas Exchange
NJBPU						New Jersey Board of Public Utilities


Non-Regulatory Agreement 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
NPS						National Park Service
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

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


PUCT						Public Utility Commission of Texas
REC						Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source

Regulatory Agreement Units						Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting

RFP						Request for Proposal
Rider						Reconcilable Surcharge Recovery Mechanism
RMC						Risk Management Committee

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
RNF						Revenues Net of Purchased Power and Fuel Expense
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



STRIDE						Maryland Strategic Infrastructure Development and Enhancement Program


Transition Bonds						Transition Bonds issued by ACE Funding

UGSOA						United Government Security Officers of America
VIE						Variable Interest Entity
WECC						Western Electric Coordinating Council
ZEC						Zero Emission Credit, or Zero Emission Certificate
ZES						Zero Emission Standard

Table of Contents

FILING FORMAT

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

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature, and expected benefits associated with the potential separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities. 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 2020 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 19, 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 15, 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, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

WHERE TO FIND MORE INFORMATION

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

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions, except per share data)	2021		2020		2021		2020
Operating revenues
Competitive businesses revenues	$	3,900	$	3,612	$	9,165	$	8,016
Rate-regulated utility revenues	3,968		3,832		8,464		8,108
Revenues from alternative revenue programs	47		(122)		176		(55)
Total operating revenues	7,915		7,322		17,805		16,069
Operating expenses
Competitive businesses purchased power and fuel	1,952		1,945		6,562		4,655
Rate-regulated utility purchased power and fuel	1,064		979		2,422		2,136

Operating and maintenance	2,447		2,433		4,426		4,637
Depreciation and amortization	1,666		1,001		3,363		2,023
Taxes other than income taxes	432		411		870		847
Total operating expenses	7,561		6,769		17,643		14,298

Gain on sales of assets and businesses	12		12		83		13


Operating income	366		565		245		1,784
Other income and (deductions)
Interest expense, net	(390)		(421)		(770)		(824)
Interest expense to affiliates	(6)		(6)		(13)		(13)
Other, net	581		656		806		(68)
Total other income and (deductions)	185		229		23		(905)
Income before income taxes	551		794		268		879
Income taxes	74		219		55		(75)
Equity in losses of unconsolidated affiliates	(1)		(1)		(2)		(4)
Net income	476		574		211		950
Net income (loss) attributable to noncontrolling interests	75		53		99		(153)
Net income attributable to common shareholders	$	401	$	521	$	112	$	1,103
Comprehensive income, net of income taxes
Net income	$	476	$	574	$	211	$	950
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(1)		(10)		(2)		(20)
Actuarial loss reclassified to periodic benefit cost	56		47		112		94
Pension and non-pension postretirement benefit plan valuation adjustment	—		2		(2)		(5)
Unrealized loss on cash flow hedges	—		—		—		(1)

Unrealized gain (loss) on foreign currency translation	2		2		3		(6)


Other comprehensive income	57		41		111		62
Comprehensive income	533		615		322		1,012
Comprehensive income (loss) attributable to noncontrolling interests	75		53		99		(153)
Comprehensive income attributable to common shareholders	$	458	$	562	$	223	$	1,165

Average shares of common stock outstanding:
Basic	978		976		978		975
Assumed exercise and/or distributions of stock-based awards	1		—		1		1
Diluted(a)	979		976		979		976

Earnings per average common share
Basic	$	0.41	$	0.53	$	0.11	$	1.13
Diluted	$	0.41	$	0.53	$	0.11	$	1.13

__________

(a)The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was zero for the three and six months ended June 30, 2021 and 1 million and less than 1 million for the three and six months ended June 30, 2020, respectively.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	211	$	950
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	4,180		2,741
Asset impairments	500		33

Gain on sales of assets and businesses	(83)		(13)

Deferred income taxes and amortization of investment tax credits	(163)		33
Net fair value changes related to derivatives	(490)		(194)
Net realized and unrealized (gains) losses on NDT funds	(376)		196
Net unrealized gains on equity investments	(96)		—
Other non-cash operating activities	(331)		671
Changes in assets and liabilities:
Accounts receivable	(16)		1,318
Inventories	1		(14)
Accounts payable and accrued expenses	(87)		(798)
Option premiums received (paid), net	2		(102)
Collateral received, net	957		340
Income taxes	190		(114)
Pension and non-pension postretirement benefit contributions	(559)		(558)
Other assets and liabilities	(2,702)		(1,809)
Net cash flows provided by operating activities	1,138		2,680
Cash flows from investing activities
Capital expenditures	(4,040)		(3,773)
Proceeds from NDT fund sales	4,438		2,488
Investment in NDT funds	(4,538)		(2,540)
Collection of DPP	2,209		1,102


Proceeds from sales of assets and businesses	724		—


Other investing activities	17		4
Net cash flows used in investing activities	(1,190)		(2,719)
Cash flows from financing activities
Changes in short-term borrowings	(666)		(751)
Proceeds from short-term borrowings with maturities greater than 90 days	500		500

Issuance of long-term debt	2,455		6,526
Retirement of long-term debt	(630)		(3,894)





Dividends paid on common stock	(747)		(746)

Proceeds from employee stock plans	47		46
Other financing activities	(64)		(84)
Net cash flows provided by financing activities	895		1,597
Increase in cash, restricted cash, and cash equivalents	843		1,558
Cash, restricted cash, and cash equivalents at beginning of period	1,166		1,122
Cash, restricted cash, and cash equivalents at end of period	$	2,009	$	2,680

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(313)	$	(105)
Increase in DPP	1,958		1,754

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	1,578	$	663
Restricted cash and cash equivalents	379		438

Accounts receivable
Customer accounts receivable	3,533		3,597
Customer allowance for credit losses	(395)		(366)
Customer accounts receivable, net	3,138		3,231
Other accounts receivable	1,426		1,469
Other allowance for credit losses	(72)		(71)
Other accounts receivable, net	1,354		1,398
Mark-to-market derivative assets	749		644
Unamortized energy contract assets	37		38
Inventories, net
Fossil fuel and emission allowances	259		297
Materials and supplies	1,443		1,425
Regulatory assets	1,252		1,228
Renewable energy credits	368		633
Assets held for sale	11		958
Other	1,780		1,609
Total current assets	12,348		12,562
Property, plant, and equipment (net of accumulated depreciation and amortization of $28,783 and $26,727 as of June 30, 2021 and December 31, 2020, respectively)	82,120		82,584
Deferred debits and other assets
Regulatory assets	8,745		8,759
Nuclear decommissioning trust funds	15,400		14,464
Investments	421		440
Goodwill	6,677		6,677
Mark-to-market derivative assets	443		555
Unamortized energy contract assets	278		294

Other	2,964		2,982
Total deferred debits and other assets	34,928		34,171
Total assets(a)	$	129,396	$	129,317

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	1,865	$	2,031
Long-term debt due within one year	3,633		1,819
Accounts payable	3,547		3,562
Accrued expenses	1,719		2,078
Payables to affiliates	5		5
Regulatory liabilities	686		581
Mark-to-market derivative liabilities	719		295
Unamortized energy contract liabilities	95		100
Renewable energy credit obligation	509		661
Liabilities held for sale	2		375
Other	1,139		1,264
Total current liabilities	13,919		12,771
Long-term debt	35,077		35,093
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	13,194		13,035
Asset retirement obligations	12,502		12,300
Pension obligations	3,880		4,503
Non-pension postretirement benefit obligations	1,983		2,011
Spent nuclear fuel obligation	1,209		1,208
Regulatory liabilities	9,148		9,485
Mark-to-market derivative liabilities	554		473
Unamortized energy contract liabilities	192		238

Other	2,848		2,942
Total deferred credits and other liabilities	45,510		46,195
Total liabilities(a)	94,896		94,449
Commitments and contingencies

Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 978 shares and 976 shares outstanding at June 30, 2021 and December 31, 2020, respectively)	19,454		19,373
Treasury stock, at cost (2 shares at June 30, 2021 and December 31, 2020)	(123)		(123)
Retained earnings	16,098		16,735
Accumulated other comprehensive loss, net	(3,289)		(3,400)
Total shareholders’ equity	32,140		32,585
Noncontrolling interests	2,360		2,283
Total equity	34,500		34,868
Total liabilities and shareholders’ equity	$	129,396	$	129,317

__________

(a)Exelon’s consolidated assets include $10,093 million and $10,200 million at June 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,578 million and $3,598 million at June 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 17 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


	Six Months Ended June 30, 2021
(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, 2020	977,466	$	19,373	$	(123)	$	16,735	$	(3,400)	$	2,283	$	34,868
Net (loss) income	—	—		—		(289)		—		25		(264)
Long-term incentive plan activity	640	5		—		—		—		—		5
Employee stock purchase plan issuances	902	34		—		—		—		—		34


Changes in equity of noncontrolling interests	—	—		—		—		—		(10)		(10)

Common stock dividends ($0.38/common share)	—	—		—		(374)		—		—		(374)
Other comprehensive income, net of income taxes	—	—		—		—		54		—		54

Balance, March 31, 2021	979,008	$	19,412	$	(123)	$	16,072	$	(3,346)	$	2,298	$	34,313
Net income	—	—		—		401		—		75		476
Long-term incentive plan activity	237	24		—		—		—		—		24
Employee stock purchase plan issuances	420	18		—		—		—		—		18

Changes in equity of noncontrolling interests	—	—		—		—		—		(13)		(13)


Common stock dividends ($0.38/common share)	—	—		—		(375)		—		—		(375)
Other comprehensive income, net of income taxes	—	—		—		—		57		—		57

Balance, June 30, 2021	979,665	$	19,454	$	(123)	$	16,098	$	(3,289)	$	2,360	$	34,500

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


	Six Months Ended June 30, 2020
(In millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Loss, net		Noncontrolling Interests		Total Shareholders' Equity
Balance, December 31, 2019	974,416	$	19,274	$	(123)	$	16,267	$	(3,194)	$	2,349	$	34,573
Net income (loss)	—	—		—		582		—		(206)		376
Long-term incentive plan activity	1,354	(4)		—		—		—		—		(4)
Employee stock purchase plan issuances	470	31		—		—		—		—		31


Changes in equity of noncontrolling interests	—	—		—		—		—		(9)		(9)
Sale of noncontrolling interests	—	2		—		—		—		—		2
Common stock dividends ($0.38/common share)	—	—		—		(374)		—		—		(374)
Other comprehensive income, net of income taxes	—	—		—		—		21		—		21

Balance, March 31, 2020	976,240	$	19,303	$	(123)	$	16,475	$	(3,173)	$	2,134	$	34,616
Net income	—	—		—		521		—		53		574
Long-term incentive plan activity	148	17		—		—		—		—		17
Employee stock purchase plan issuances	(51)	15		—		—		—		—		15

Changes in equity of noncontrolling interests	—	—		—		—		—		(19)		(19)
Sale of noncontrolling interests	—	1		—		—		—		—		1
Common stock dividends ($0.38/common share)	—	—		—		(374)		—		—		(374)
Other comprehensive income, net of income taxes	—	—		—		—		41		—		41
Balance, June 30, 2020	976,337	$	19,336	$	(123)	$	16,622	$	(3,132)	$	2,168	$	34,871

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2021		2020		2021		2020
Operating revenues
Operating revenues	$	3,899	$	3,609	$	9,163	$	8,012
Operating revenues from affiliates	254		271		549		601
Total operating revenues	4,153		3,880		9,712		8,613
Operating expenses
Purchased power and fuel	1,952		1,945		6,562		4,655
Purchased power and fuel from affiliates	(5)		(3)		(5)		(9)
Operating and maintenance	1,337		1,053		2,194		2,174
Operating and maintenance from affiliates	137		136		282		277
Depreciation and amortization	930		300		1,869		604
Taxes other than income taxes	118		116		239		246
Total operating expenses	4,469		3,547		11,141		7,947

Gain on sales of assets and businesses	8		12		79		12


Operating (loss) income	(308)		345		(1,350)		678
Other income and (deductions)
Interest expense, net	(72)		(78)		(140)		(179)
Interest expense to affiliates	(4)		(9)		(8)		(18)
Other, net	508		602		675		(168)
Total other income and (deductions)	432		515		527		(365)
Income (loss) before income taxes	124		860		(823)		313
Income taxes	110		329		(70)		(59)
Equity in losses of unconsolidated affiliates	(1)		(2)		(3)		(4)
Net income (loss)	13		529		(756)		368
Net income (loss) attributable to noncontrolling interests	74		53		98		(153)
Net (loss) income attributable to membership interest	$	(61)	$	476	$	(854)	$	521
Comprehensive income, net of income taxes
Net income (loss)	$	13	$	529	$	(756)	$	368
Other comprehensive income (loss), net of income taxes
Unrealized loss on cash flow hedges	—		—		—		(1)

Unrealized gain (loss) on foreign currency translation	2		2		3		(6)


Other comprehensive income (loss), net of income taxes	2		2		3		(7)
Comprehensive income (loss)	15		531		(753)		361
Comprehensive income (loss) attributable to noncontrolling interests	74		53		98		(153)
Comprehensive (loss) income attributable to membership interest	$	(59)	$	478	$	(851)	$	514

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2021		2020
Cash flows from operating activities
Net (loss) income	$	(756)	$	368
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	2,686		1,320
Asset impairments	493		18

Gain on sales of assets and businesses	(79)		(12)

Deferred income taxes and amortization of investment tax credits	(142)		(54)
Net fair value changes related to derivatives	(490)		(193)
Net realized and unrealized (gains) losses on NDT funds	(376)		196
Net unrealized gains on equity investments	(96)		—
Other non-cash operating activities	(421)		136
Changes in assets and liabilities:
Accounts receivable	(90)		1,443
Receivables from and payables to affiliates, net	43		68
Inventories	4		(34)
Accounts payable and accrued expenses	154		(666)
Option premiums received (paid), net	2		(102)
Collateral received, net	955		342
Income taxes	(1)		26
Pension and non-pension postretirement benefit contributions	(212)		(243)
Other assets and liabilities	(2,031)		(1,332)
Net cash flows (used in) provided by operating activities	(357)		1,281
Cash flows from investing activities
Capital expenditures	(719)		(930)

Proceeds from NDT fund sales	4,438		2,488
Investment in NDT funds	(4,538)		(2,540)

Collection of DPP	2,209		1,102

Proceeds from sales of assets and businesses	724		—



Other investing activities	(8)		6
Net cash flows provided by investing activities	2,106		126
Cash flows from financing activities
Changes in short-term borrowings	(340)		(220)
Proceeds from short-term borrowings with maturities greater than 90 days	—		500

Issuance of long-term debt	151		2,403
Retirement of long-term debt	(56)		(2,936)

Changes in Exelon intercompany money pool	(285)		—
Distributions to member	(916)		(937)




Other financing activities	(29)		(30)
Net cash flows used in financing activities	(1,475)		(1,220)
Increase in cash, restricted cash, and cash equivalents	274		187
Cash, restricted cash, and cash equivalents at beginning of period	327		449
Cash, restricted cash, and cash equivalents at end of period	$	601	$	636

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(66)	$	(108)
Increase in DPP	1,958		1,754

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	542	$	226
Restricted cash and cash equivalents	59		89
Accounts receivable
Customer accounts receivable	1,410		1,330
Customer allowance for credit losses	(75)		(32)
Customer accounts receivable, net	1,335		1,298
Other accounts receivable	476		352
Other allowance for credit losses	(1)		—
Other accounts receivable, net	475		352
Mark-to-market derivative assets	749		644
Receivables from affiliates	117		153

Unamortized energy contract assets	37		38
Inventories, net
Fossil fuel and emission allowances	204		233
Materials and supplies	986		978

Renewable energy credits	341		621
Assets held for sale	11		958
Other	1,353		1,357
Total current assets	6,209		6,947
Property, plant, and equipment (net of accumulated depreciation and amortization of $15,024 and $13,370 as of June 30, 2021 and December 31, 2020, respectively)	19,837		22,214
Deferred debits and other assets
Nuclear decommissioning trust funds	15,400		14,464
Investments	157		184
Goodwill	47		47
Mark-to-market derivative assets	441		555

Prepaid pension asset	1,713		1,558

Unamortized energy contract assets	278		293
Deferred income taxes	14		6
Other	1,725		1,826
Total deferred debits and other assets	19,775		18,933
Total assets(a)	$	45,821	$	48,094

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	500	$	840
Long-term debt due within one year	1,229		197

Accounts payable	1,489		1,253
Accrued expenses	654		788
Payables to affiliates	119		107
Borrowings from Exelon intercompany money pool	—		285

Mark-to-market derivative liabilities	695		262
Unamortized energy contract liabilities	4		7
Renewable energy credit obligation	508		661
Liabilities held for sale	2		375
Other	313		444
Total current liabilities	5,513		5,219
Long-term debt	4,627		5,566
Long-term debt to affiliates	322		324

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	3,460		3,656
Asset retirement obligations	12,257		12,054

Non-pension postretirement benefit obligations	857		858
Spent nuclear fuel obligation	1,209		1,208
Payables to affiliates	3,011		3,017
Mark-to-market derivative liabilities	311		205
Unamortized energy contract liabilities	3		3

Other	1,266		1,308
Total deferred credits and other liabilities	22,374		22,309
Total liabilities(a)	32,836		33,418
Commitments and contingencies

Equity
Member’s equity
Membership interest	9,624		9,624
Undistributed earnings	1,035		2,805
Accumulated other comprehensive loss, net	(27)		(30)
Total member’s equity	10,632		12,399
Noncontrolling interests	2,353		2,277
Total equity	12,985		14,676
Total liabilities and equity	$	45,821	$	48,094

__________

(a)Generation’s consolidated assets include $10,077 million and $10,182 million at June 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,563 million and $3,572 million at June 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 17 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)


	Six Months Ended June 30, 2021
	Member’s Equity
(In millions)	Membership Interest		Undistributed Earnings		Accumulated Other Comprehensive Loss, net		Noncontrolling Interests		Total Equity
Balance, December 31, 2020	$	9,624	$	2,805	$	(30)	$	2,277	$	14,676
Net (loss) income	—		(793)		—		24		(769)
Changes in equity of noncontrolling interests	—		—		—		(10)		(10)




Distributions to member	—		(458)		—		—		(458)
Other comprehensive income, net of income taxes	—		—		1		—		1

Balance, March 31, 2021	$	9,624	$	1,554	$	(29)	$	2,291	$	13,440
Net (loss) income	—		(61)		—		74		13
Changes in equity of noncontrolling interests	—		—		—		(12)		(12)




Distributions to member	—		(458)		—		—		(458)
Other comprehensive income, net of income taxes	—		—		2		—		2
Balance, June 30, 2021	$	9,624	$	1,035	$	(27)	$	2,353	$	12,985


	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

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2021		2020		2021		2020
Operating revenues
Electric operating revenues	$	1,503	$	1,431	$	2,977	$	2,853
Revenues from alternative revenue programs	9		(25)		64		(13)
Operating revenues from affiliates	5		11		11		16
Total operating revenues	1,517		1,417		3,052		2,856
Operating expenses
Purchased power	421		380		862		770
Purchased power from affiliate	79		84		163		181
Operating and maintenance	250		469		495		713
Operating and maintenance from affiliates	73		67		144		140
Depreciation and amortization	296		274		589		547
Taxes other than income taxes	77		71		153		146
Total operating expenses	1,196		1,345		2,406		2,497

Operating income	321		72		646		359
Other income and (deductions)
Interest expense, net	(95)		(95)		(187)		(186)
Interest expense to affiliates	(3)		(3)		(6)		(6)
Other, net	15		11		22		22
Total other income and (deductions)	(83)		(87)		(171)		(170)
Income (loss) before income taxes	238		(15)		475		189
Income taxes	46		46		85		82
Net income (loss)	$	192	$	(61)	$	390	$	107
Comprehensive income (loss)	$	192	$	(61)	$	390	$	107

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	390	$	107
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	589		547
Asset impairments	—		15
Deferred income taxes and amortization of investment tax credits	143		129

Other non-cash operating activities	23		283
Changes in assets and liabilities:
Accounts receivable	(48)		(92)
Receivables from and payables to affiliates, net	5		(6)
Inventories	(2)		(7)
Accounts payable and accrued expenses	(45)		4
Collateral received (posted), net	2		(3)
Income taxes	(34)		(90)
Pension and non-pension postretirement benefit contributions	(173)		(144)
Other assets and liabilities	(292)		(245)
Net cash flows provided by operating activities	558		498
Cash flows from investing activities
Capital expenditures	(1,162)		(1,029)




Other investing activities	12		(4)
Net cash flows used in investing activities	(1,150)		(1,033)
Cash flows from financing activities
Changes in short-term borrowings	(290)		(130)
Issuance of long-term debt	700		1,000


Dividends paid on common stock	(253)		(249)
Contributions from parent	395		249


Other financing activities	(11)		(14)
Net cash flows provided by financing activities	541		856
(Decrease) increase in cash, restricted cash, and cash equivalents	(51)		321
Cash, restricted cash, and cash equivalents at beginning of period	405		403
Cash, restricted cash, and cash equivalents at end of period	$	354	$	724

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(93)	$	18

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	71	$	83
Restricted cash and cash equivalents	240		279
Accounts receivable
Customer accounts receivable	687		656
Customer allowance for credit losses	(89)		(97)
Customer accounts receivable, net	598		559
Other accounts receivable	257		239
Other allowance for credit losses	(18)		(21)
Other accounts receivable, net	239		218

Receivables from affiliates	22		22


Inventories, net	170		170

Regulatory assets	298		279

Other	77		49
Total current assets	1,715		1,659
Property, plant, and equipment (net of accumulated depreciation and amortization of $5,885 and $5,672 as of June 30, 2021 and December 31, 2020, respectively)	25,170		24,557
Deferred debits and other assets
Regulatory assets	1,846		1,749
Investments	6		6

Goodwill	2,625		2,625
Receivables from affiliates	2,439		2,541
Prepaid pension asset	1,138		1,022


Other	385		307
Total deferred debits and other assets	8,439		8,250
Total assets	$	35,324	$	34,466

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	33	$	323
Long-term debt due within one year	350		350
Accounts payable	575		683
Accrued expenses	346		390
Payables to affiliates	102		96

Customer deposits	90		86
Regulatory liabilities	419		289
Mark-to-market derivative liabilities	23		33

Other	147		143
Total current liabilities	2,085		2,393
Long-term debt	9,325		8,633
Long-term debt to financing trust	205		205
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	4,531		4,341
Asset retirement obligations	128		126

Non-pension postretirement benefits obligations	180		173

Regulatory liabilities	6,181		6,403
Mark-to-market derivative liabilities	242		268


Other	587		595
Total deferred credits and other liabilities	11,849		11,906
Total liabilities	23,464		23,137
Commitments and contingencies
Shareholders’ equity
Common stock	1,588		1,588


Other paid-in capital	8,680		8,285
Retained deficit unappropriated	(1,639)		(1,639)
Retained earnings appropriated	3,231		3,095

Total shareholders’ equity	11,860		11,329
Total liabilities and shareholders’ equity	$	35,324	$	34,466

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


	Six Months Ended June 30, 2021
(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated		Retained Earnings Appropriated		Total Shareholders’ Equity
Balance, December 31, 2020	$	1,588	$	8,285	$	(1,639)	$	3,095	$	11,329
Net income	—		—		197		—		197
Appropriation of retained earnings for future dividends	—		—		(197)		197		—
Common stock dividends	—		—		—		(127)		(127)
Contributions from parent	—		198		—		—		198
Balance, March 31, 2021	$	1,588	$	8,483	$	(1,639)	$	3,165	$	11,597
Net income	—		—		192		—		192
Appropriation of retained earnings for future dividends	—		—		(192)		192		—
Common stock dividends	—		—		—		(126)		(126)
Contributions from parent	—		197		—		—		197
Balance, June 30, 2021	$	1,588	$	8,680	$	(1,639)	$	3,231	$	11,860






	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

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2021		2020		2021		2020
Operating revenues
Electric operating revenues	$	602	$	580	$	1,251	$	1,180
Natural gas operating revenues	82		95		310		304
Revenues from alternative revenue programs	7		4		17		5
Operating revenues from affiliates	2		2		4		4
Total operating revenues	693		681		1,582		1,493
Operating expenses
Purchased power	145		142		334		306
Purchased fuel	22		34		108		117
Purchased power from affiliate	40		40		81		76
Operating and maintenance	166		235		360		414
Operating and maintenance from affiliates	43		40		83		78
Depreciation and amortization	87		88		173		173
Taxes other than income taxes	49		39		92		78
Total operating expenses	552		618		1,231		1,242

Operating income	141		63		351		251
Other income and (deductions)
Interest expense, net	(39)		(33)		(74)		(65)
Interest expense to affiliates	(3)		(3)		(6)		(6)
Other, net	7		5		12		7
Total other income and (deductions)	(35)		(31)		(68)		(64)
Income before income taxes	106		32		283		187
Income taxes	2		(7)		12		9

Net income	$	104	$	39	$	271	$	178
Comprehensive income	$	104	$	39	$	271	$	178

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	271	$	178
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	173		173


Deferred income taxes and amortization of investment tax credits	21		6
Other non-cash operating activities	(5)		25
Changes in assets and liabilities:
Accounts receivable	86		22
Receivables from and payables to affiliates, net	2		3
Inventories	3		10
Accounts payable and accrued expenses	(46)		27

Income taxes	24		15
Pension and non-pension postretirement benefit contributions	(15)		(18)
Other assets and liabilities	(140)		(48)
Net cash flows provided by operating activities	374		393
Cash flows from investing activities
Capital expenditures	(577)		(512)
Changes in Exelon intercompany money pool	—		68

Other investing activities	4		3
Net cash flows used in investing activities	(573)		(441)
Cash flows from financing activities


Issuance of long-term debt	375		350


Changes in Exelon intercompany money pool	(40)		—
Dividends paid on common stock	(169)		(170)
Contributions from parent	395		231


Other financing activities	(4)		(3)
Net cash flows provided by financing activities	557		408
Increase in cash, restricted cash, and cash equivalents	358		360
Cash, restricted cash, and cash equivalents at beginning of period	26		27
Cash, restricted cash, and cash equivalents at end of period	$	384	$	387

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(16)	$	42

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	376	$	19
Restricted cash and cash equivalents	8		7
Accounts receivable
Customer accounts receivable	419		511
Customer allowance for credit losses	(111)		(116)
Customer accounts receivable, net	308		395
Other accounts receivable	106		130
Other allowance for credit losses	(7)		(8)
Other accounts receivable, net	99		122

Receivables from affiliates	—		2


Inventories, net
Fossil fuel	25		33
Materials and supplies	42		38
Prepaid utility taxes	76		—
Regulatory assets	30		25

Other	37		21
Total current assets	1,001		662
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,906 and $3,843 as of June 30, 2021 and December 31, 2020, respectively)	10,581		10,181
Deferred debits and other assets
Regulatory assets	866		776

Investments	32		30



Receivables from affiliates	571		475
Prepaid pension asset	387		375


Other	53		32
Total deferred debits and other assets	1,909		1,688
Total assets	$	13,491	$	12,531

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities

Long-term debt due within one year	$	300	$	300
Accounts payable	436		479
Accrued expenses	125		129
Payables to affiliates	50		50
Borrowings from Exelon intercompany money pool	—		40
Customer deposits	50		59
Regulatory liabilities	109		121


Other	29		30
Total current liabilities	1,099		1,208
Long-term debt	3,825		3,453
Long-term debt to financing trusts	184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,345		2,242
Asset retirement obligations	29		29
Non-pension postretirement benefits obligations	287		286

Regulatory liabilities	600		503




Other	92		93
Total deferred credits and other liabilities	3,353		3,153
Total liabilities	8,461		7,998
Commitments and contingencies
Shareholder’s equity
Common stock	3,409		3,014


Retained earnings	1,621		1,519


Total shareholder’s equity	5,030		4,533
Total liabilities and shareholder's equity	$	13,491	$	12,531

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)


	Six Months Ended June 30, 2021
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance, December 31, 2020	$	3,014	$	1,519	$	4,533
Net income	—		167		167
Common stock dividends	—		(85)		(85)

Balance, March 31, 2021	$	3,014	$	1,601	$	4,615
Net income	—		104		104
Common stock dividends	—		(84)		(84)
Contributions from parent	395		—		395

Balance, June 30, 2021	$	3,409	$	1,621	$	5,030





	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

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2021		2020		2021		2020
Operating revenues
Electric operating revenues	$	560	$	530	$	1,180	$	1,125
Natural gas operating revenues	125		119		455		419
Revenues from alternative revenue programs	(10)		(37)		8		—
Operating revenues from affiliates	7		4		13		10
Total operating revenues	682		616		1,656		1,554
Operating expenses
Purchased power	133		107		295		221
Purchased fuel	27		18		126		95
Purchased power and fuel from affiliate	59		69		129		167
Operating and maintenance	147		146		299		293
Operating and maintenance from affiliates	46		41		91		83
Depreciation and amortization	141		129		293		272
Taxes other than income taxes	67		63		139		132
Total operating expenses	620		573		1,372		1,263

Operating income	62		43		284		291
Other income and (deductions)
Interest expense, net	(34)		(32)		(67)		(64)

Other, net	9		6		16		10
Total other income and (deductions)	(25)		(26)		(51)		(54)
Income before income taxes	37		17		233		237
Income taxes	(8)		(22)		(21)		18

Net income	$	45	$	39	$	254	$	219



Comprehensive income	$	45	$	39	$	254	$	219

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	254	$	219
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	293		272

Deferred income taxes and amortization of investment tax credits	11		22

Other non-cash operating activities	28		50
Changes in assets and liabilities:
Accounts receivable	73		19
Receivables from and payables to affiliates, net	(19)		(26)
Inventories	(9)		10
Accounts payable and accrued expenses	(51)		(15)
Collateral posted, net	2		—
Income taxes	(27)		26
Pension and non-pension postretirement benefit contributions	(71)		(68)
Other assets and liabilities	(96)		(5)
Net cash flows provided by operating activities	388		504
Cash flows from investing activities
Capital expenditures	(620)		(548)

Other investing activities	10		(4)
Net cash flows used in investing activities	(610)		(552)
Cash flows from financing activities
Changes in short-term borrowings	—		(76)
Issuance of long-term debt	600		400





Dividends paid on common stock	(146)		(123)
Contributions from parent	—		26
Other financing activities	(6)		(8)
Net cash flows provided by financing activities	448		219
Increase in cash, restricted cash, and cash equivalents	226		171
Cash, restricted cash, and cash equivalents at beginning of period	145		25
Cash, restricted cash, and cash equivalents at end of period	$	371	$	196

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(71)	$	(14)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	368	$	144
Restricted cash and cash equivalents	3		1
Accounts receivable
Customer accounts receivable	398		487
Customer allowance for credit losses	(27)		(35)
Customer accounts receivable, net	371		452
Other accounts receivable	146		117
Other allowance for credit losses	(8)		(9)
Other accounts receivable, net	138		108

Receivables from affiliates	—		3



Inventories, net
Fossil fuel	27		25
Materials and supplies	48		41

Regulatory assets	177		168

Other	9		6
Total current assets	1,141		948
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,151 and $4,034 as of June 30, 2021 and December 31, 2020, respectively)	10,200		9,872
Deferred debits and other assets
Regulatory assets	473		481

Investments	13		10



Prepaid pension asset	302		270


Other	57		69
Total deferred debits and other assets	845		830
Total assets	$	12,186	$	11,650

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities

Long-term debt due within one year	$	300	$	300
Accounts payable	287		346
Accrued expenses	138		205
Payables to affiliates	41		61

Customer deposits	101		110
Regulatory liabilities	32		30


Other	87		91
Total current liabilities	986		1,143
Long-term debt	3,959		3,364

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,643		1,521
Asset retirement obligations	24		23
Non-pension postretirement benefits obligations	179		189

Regulatory liabilities	998		1,109




Other	92		104
Total deferred credits and other liabilities	2,936		2,946
Total liabilities	7,881		7,453
Commitments and contingencies
Shareholder's equity
Common stock	2,318		2,318


Retained earnings	1,987		1,879


Total shareholder's equity	4,305		4,197


Total liabilities and shareholder's equity	$	12,186	$	11,650

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)


	Six Months Ended June 30, 2021
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance, December 31, 2020	$	2,318	$	1,879	$	4,197
Net income	—		209		209
Common stock dividends	—		(74)		(74)

Balance, March 31, 2021	$	2,318	$	2,014	$	4,332
Net income	—		45		45
Common stock dividends	—		(72)		(72)





Balance, June 30, 2021	$	2,318	$	1,987	$	4,305

	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

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2021		2020		2021		2020
Operating revenues
Electric operating revenues	$	1,071	$	1,047	$	2,195	$	2,133
Natural gas operating revenues	24		30		94		94
Revenues from alternative revenue programs	41		(64)		88		(47)
Operating revenues from affiliates	4		3		7		7
Total operating revenues	1,140		1,016		2,384		2,187
Operating expenses
Purchased power	308		286		656		586
Purchased fuel	9		11		41		42
Purchased power from affiliates	79		78		177		182
Operating and maintenance	217		245		434		464
Operating and maintenance from affiliates	39		36		79		74
Depreciation and amortization	194		191		404		385
Taxes other than income taxes	109		109		222		222
Total operating expenses	955		956		2,013		1,955

Gain on sales of assets	—		—		—		2
Operating income	185		60		371		234
Other income and (deductions)
Interest expense, net	(67)		(67)		(134)		(134)

Other, net	20		14		36		26
Total other income and (deductions)	(47)		(53)		(98)		(108)
Income before income taxes	138		7		273		126
Income taxes	(3)		(87)		5		(76)
Equity in earnings of unconsolidated affiliate	—		—		1		—
Net income	$	141	$	94	$	269	$	202








Comprehensive income	$	141	$	94	$	269	$	202

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	269	$	202

Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	404		385


Deferred income taxes and amortization of investment tax credits	10		(74)

Other non-cash operating activities	(50)		107
Changes in assets and liabilities:
Accounts receivable	(30)		(64)
Receivables from and payables to affiliates, net	(22)		(22)
Inventories	3		6
Accounts payable and accrued expenses	(35)		14


Income taxes	(1)		(30)
Pension and non-pension postretirement benefit contributions	(40)		(31)
Other assets and liabilities	(131)		(146)
Net cash flows provided by operating activities	377		347
Cash flows from investing activities
Capital expenditures	(889)		(686)




Other investing activities	(2)		2
Net cash flows used in investing activities	(891)		(684)
Cash flows from financing activities
Changes in short-term borrowings	(36)		(189)


Issuance of long-term debt	625		373
Retirement of long-term debt	(249)		(35)
Changes in Exelon intercompany money pool	(12)		10



Distributions to member	(414)		(268)
Contributions from member	560		359


Other financing activities	(8)		(8)
Net cash flows provided by financing activities	466		242
Decrease in cash, restricted cash, and cash equivalents	(48)		(95)
Cash, restricted cash, and cash equivalents at beginning of period	160		181
Cash, restricted cash, and cash equivalents at end of period	$	112	$	86

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(41)	$	(24)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	61	$	111
Restricted cash and cash equivalents	42		39
Accounts receivable
Customer accounts receivable	617		611
Customer allowance for credit losses	(93)		(86)
Customer accounts receivable, net	524		525
Other accounts receivable	286		260
Other allowance for credit losses	(38)		(33)
Other accounts receivable, net	248		227

Receivables from affiliates	1		8


Inventories, net
Fossil fuel	5		6
Materials and supplies	196		198


Regulatory assets	431		440

Other	77		45
Total current assets	1,585		1,599
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,827 and $1,811 as of June 30, 2021 and December 31, 2020, respectively)	15,927		15,377
Deferred debits and other assets
Regulatory assets	1,898		1,933
Investments	145		140
Goodwill	4,005		4,005


Prepaid pension asset	370		365

Deferred income taxes	10		10
Other	295		307
Total deferred debits and other assets	6,723		6,760
Total assets(a)	$	24,235	$	23,736

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings	$	332	$	368
Long-term debt due within one year	300		347
Accounts payable	517		539
Accrued expenses	246		299
Payables to affiliates	75		104
Borrowings from Exelon intercompany money pool	9		21

Customer deposits	89		106
Regulatory liabilities	123		137
Unamortized energy contract liabilities	92		92

Other	131		141
Total current liabilities	1,914		2,154
Long-term debt	7,069		6,659
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,541		2,439
Asset retirement obligations	59		59
Non-pension postretirement benefit obligations	75		86
Regulatory liabilities	1,338		1,438




Unamortized energy contract liabilities	190		235
Other	590		622
Total deferred credits and other liabilities	4,793		4,879
Total liabilities(a)	13,776		13,692
Commitments and contingencies

Member's equity
Membership interest	10,672		10,112

Undistributed losses	(213)		(68)

Total member's equity	10,459		10,044
Total liabilities and member's equity	$	24,235	$	23,736

__________

(a)PHI’s consolidated total assets include $16 million and $18 million at June 30, 2021 and December 31, 2020, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $15 million and $26 million at June 30, 2021 and December 31, 2020, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 17 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY

(Unaudited)


	Six Months Ended June 30, 2021
(In millions)	Membership Interest		Undistributed (Losses)/Earnings		Total Member's Equity
Balance, December 31, 2020	$	10,112	$	(68)	$	10,044
Net income	—		128		128
Distributions to member	—		(81)		(81)
Contributions from member	560		—		560
Balance, March 31, 2021	$	10,672	$	(21)	$	10,651
Net income	—		141		141
Distributions to member	—		(333)		(333)






Balance, June 30, 2021	$	10,672	$	(213)	$	10,459


	Six Months Ended June 30, 2020
(In millions)	Membership Interest		Undistributed (Losses)/Earnings		Total 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

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2021		2020		2021		2020
Operating revenues
Electric operating revenues	$	503	$	506	$	1,027	$	1,034
Revenues from alternative revenue programs	19		(13)		46		2
Operating revenues from affiliates	1		1		3		3
Total operating revenues	523		494		1,076		1,039
Operating expenses
Purchased power	76		78		168		164
Purchased power from affiliate	57		60		130		139
Operating and maintenance	62		67		118		128
Operating and maintenance from affiliates	51		52		103		103
Depreciation and amortization	96		92		199		186
Taxes other than income taxes	87		87		177		179
Total operating expenses	429		436		895		899



Operating income	94		58		181		140
Other income and (deductions)
Interest expense, net	(35)		(34)		(69)		(68)

Other, net	13		9		25		18
Total other income and (deductions)	(22)		(25)		(44)		(50)
Income before income taxes	72		33		137		90
Income taxes	(3)		(24)		3		(19)

Net income	$	75	$	57	$	134	$	109










Comprehensive income	$	75	$	57	$	134	$	109

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	134	$	109
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	199		186

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

Other non-cash operating activities	(43)		11
Changes in assets and liabilities:
Accounts receivable	(23)		(45)
Receivables from and payables to affiliates, net	(11)		(22)
Inventories	1		3
Accounts payable and accrued expenses	(26)		11
Income taxes	(20)		(18)
Pension and non-pension postretirement benefit contributions	(7)		(6)
Other assets and liabilities	(79)		(52)
Net cash flows provided by operating activities	135		155
Cash flows from investing activities
Capital expenditures	(439)		(324)




Other investing activities	(2)		(3)
Net cash flows used in investing activities	(441)		(327)
Cash flows from financing activities
Changes in short-term borrowings	119		(68)
Issuance of long-term debt	150		150
Retirement of long-term debt	—		(1)
Changes in PHI intercompany money pool	9		50
Dividends paid on common stock	(123)		(101)
Contributions from parent	138		137


Other financing activities	(2)		(6)
Net cash flows provided by financing activities	291		161
Decrease in cash, restricted cash, and cash equivalents	(15)		(11)
Cash, restricted cash, and cash equivalents at beginning of period	65		63
Cash, restricted cash, and cash equivalents at end of period	$	50	$	52

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(15)	$	(28)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	17	$	30
Restricted cash and cash equivalents	33		35
Accounts receivable
Customer accounts receivable	290		279
Customer allowance for credit losses	(38)		(32)
Customer accounts receivable, net	252		247
Other accounts receivable	155		131
Other allowance for credit losses	(16)		(13)
Other accounts receivable, net	139		118

Receivables from affiliates	—		2


Inventories, net	110		111



Regulatory assets	215		214

Other	13		13
Total current assets	779		770
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,782 and $3,697 as of June 30, 2021 and December 31, 2020, respectively)	7,771		7,456
Deferred debits and other assets
Regulatory assets	571		570
Investments	118		115



Prepaid pension asset	282		284

Other	67		69
Total deferred debits and other assets	1,038		1,038
Total assets	$	9,588	$	9,264

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	154	$	35
Long-term debt due within one year	204		3
Accounts payable	215		226
Accrued expenses	123		164
Payables to affiliates	42		55


Borrowings from PHI intercompany money pool	9		—
Customer deposits	41		51
Regulatory liabilities	38		46
Merger related obligation	29		33
Current portion of DC PLUG obligation	30		30
Other	29		31
Total current liabilities	914		674
Long-term debt	3,114		3,162

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,244		1,189
Asset retirement obligations	39		39

Non-pension postretirement benefit obligations	7		13




Regulatory liabilities	599		644
Other	319		340
Total deferred credits and other liabilities	2,208		2,225
Total liabilities	6,236		6,061
Commitments and contingencies
Shareholder's equity

Common stock	2,196		2,058


Retained earnings	1,156		1,145

Total shareholder's equity	3,352		3,203
Total liabilities and shareholder's equity	$	9,588	$	9,264

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)


	Six Months Ended June 30, 2021
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance, December 31, 2020	$	2,058	$	1,145	$	3,203
Net income	—		59		59
Common stock dividends	—		(28)		(28)
Contributions from parent	138		—		138
Balance, March 31, 2021	$	2,196	$	1,176	$	3,372
Net income	—		75		75



Common stock dividends	—		(95)		(95)

Balance, June 30, 2021	$	2,196	$	1,156	$	3,352


	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

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2021		2020		2021		2020
Operating revenues
Electric operating revenues	$	262	$	260	$	562	$	543
Natural gas operating revenues	24		30		95		94
Revenues from alternative revenue programs	10		(25)		19		(24)
Operating revenues from affiliates	2		2		4		4
Total operating revenues	298		267		680		617
Operating expenses
Purchased power	82		80		185		169
Purchased fuel	9		11		41		42
Purchased power from affiliates	17		16		37		38
Operating and maintenance	41		54		85		97
Operating and maintenance from affiliates	39		38		79		75
Depreciation and amortization	51		47		104		94
Taxes other than income taxes	16		17		33		32
Total operating expenses	255		263		564		547



Operating income	43		4		116		70
Other income and (deductions)
Interest expense, net	(16)		(15)		(30)		(31)
Other, net	4		2		6		5
Total other income and (deductions)	(12)		(13)		(24)		(26)
Income (loss) before income taxes	31		(9)		92		44
Income taxes	1		(28)		6		(20)

Net income	$	30	$	19	$	86	$	64
Comprehensive income	$	30	$	19	$	86	$	64

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	86	$	64
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	104		94

Deferred income taxes and amortization of investment tax credits	4		(19)

Other non-cash operating activities	(12)		40
Changes in assets and liabilities:
Accounts receivable	24		6
Receivables from and payables to affiliates, net	(12)		(2)

Accounts payable and accrued expenses	7		3

Income taxes	14		(12)

Other assets and liabilities	(22)		(21)
Net cash flows provided by operating activities	193		153
Cash flows from investing activities
Capital expenditures	(211)		(184)


Changes in PHI intercompany money pool	(9)		(55)
Other investing activities	1		(3)
Net cash flows used in investing activities	(219)		(242)
Cash flows from financing activities
Changes in short-term borrowings	(146)		(56)
Issuance of long-term debt	125		100
Retirement of long-term debt	—		(1)

Dividends paid on common stock	(63)		(66)
Contributions from parent	120		106
Other financing activities	(3)		(1)
Net cash flows provided by financing activities	33		82
Increase (decrease) in cash, restricted cash, and cash equivalents	7		(7)
Cash, restricted cash, and cash equivalents at beginning of period	15		13
Cash, restricted cash, and cash equivalents at end of period	$	22	$	6

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(14)	$	(4)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	17	$	15
Restricted cash and cash equivalents	5		—
Accounts receivable
Customer accounts receivable	139		176
Customer allowance for credit losses	(19)		(22)
Customer accounts receivable, net	120		154
Other accounts receivable	62		68
Other allowance for credit losses	(9)		(9)
Other accounts receivable, net	53		59
Receivables from affiliates	—		1
Receivable from PHI intercompany pool	9		—
Inventories, net
Fossil fuel	5		6
Materials and supplies	52		51
Prepaid utility taxes	—		11

Regulatory assets	70		58
Renewable energy credits	18		10
Other	3		3
Total current assets	352		368
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,571 and $1,533 as of June 30, 2021 and December 31, 2020, respectively)	4,425		4,314
Deferred debits and other assets
Regulatory assets	223		222

Goodwill	8		8
Prepaid pension asset	159		162
Other	62		66
Total deferred debits and other assets	452		458
Total assets	$	5,229	$	5,140

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	146
Long-term debt due within one year	82		82
Accounts payable	125		126
Accrued expenses	40		46
Payables to affiliates	23		36

Customer deposits	28		32
Regulatory liabilities	46		47
Other	14		20
Total current liabilities	358		535
Long-term debt	1,722		1,595
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	745		715
Asset retirement obligations	14		14

Non-pension postretirement benefits obligations	13		15
Regulatory liabilities	462		493
Other	96		97
Total deferred credits and other liabilities	1,330		1,334
Total liabilities	3,410		3,464
Commitments and contingencies
Shareholder's equity
Common stock	1,209		1,089

Retained earnings	610		587
Total shareholder's equity	1,819		1,676
Total liabilities and shareholder's equity	$	5,229	$	5,140

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)


	Six Months Ended June 30, 2021
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance, December 31, 2020	$	1,089	$	587	$	1,676
Net income	—		56		56
Common stock dividends	—		(40)		(40)
Contributions from parent	120		—		120
Balance, March 31, 2021	$	1,209	$	603	$	1,812
Net income	—		30		30
Common stock dividends	—		(23)		(23)

Balance, June 30, 2021	$	1,209	$	610	$	1,819


	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

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2021		2020		2021		2020
Operating revenues
Electric operating revenues	$	306	$	281	$	605	$	556
Revenues from alternative revenue programs	12		(26)		23		(25)
Operating revenues from affiliates	1		1		1		1
Total operating revenues	319		256		629		532
Operating expenses
Purchased power	149		128		302		254
Purchased power from affiliate	5		2		9		5
Operating and maintenance	39		48		82		94
Operating and maintenance from affiliates	34		34		68		66
Depreciation and amortization	40		44		87		86
Taxes other than income taxes	2		2		4		4
Total operating expenses	269		258		552		509
Gain on sale of assets	—		—		—		2


Operating income (loss)	50		(2)		77		25
Other income and (deductions)
Interest expense, net	(14)		(15)		(29)		(29)

Other, net	—		2		2		3
Total other income and (deductions)	(14)		(13)		(27)		(26)
Income (loss) before income taxes	36		(15)		50		(1)
Income taxes	(1)		(33)		(1)		(32)

Net income	$	37	$	18	$	51	$	31
Comprehensive income	$	37	$	18	$	51	$	31

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	51	$	31
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	87		86
Deferred income taxes and amortization of investment tax credits	(2)		(30)
Other non-cash operating activities	(14)		34
Changes in assets and liabilities:
Accounts receivable	(30)		(23)
Receivables from and payables to affiliates, net	4		9
Inventories	2		2
Accounts payable and accrued expenses	(2)		17
Income taxes	2		2
Pension and non-pension postretirement benefit contributions	(3)		(2)
Other assets and liabilities	(25)		(68)
Net cash flows provided by operating activities	70		58
Cash flows from investing activities
Capital expenditures	(239)		(178)


Other investing activities	—		5
Net cash flows used in investing activities	(239)		(173)
Cash flows from financing activities
Changes in short-term borrowings	(9)		(65)


Issuance of long-term debt	350		123
Retirement of long-term debt	(249)		(34)
Changes in PHI intercompany money pool	—		5
Dividends paid on common stock	(229)		(35)
Contributions from parent	303		116
Other financing activities	(4)		(1)
Net cash flows provided by financing activities	162		109
Decrease in cash, restricted cash, and cash equivalents	(7)		(6)
Cash, restricted cash, and cash equivalents at beginning of period	30		28
Cash, restricted cash, and cash equivalents at end of period	$	23	$	22

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(13)	$	7

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	11	$	17
Restricted cash and cash equivalents	3		3
Accounts receivable
Customer accounts receivable	188		156
Customer allowance for credit losses	(36)		(32)
Customer accounts receivable, net	152		124
Other accounts receivable	69		72
Other allowance for credit losses	(13)		(11)
Other accounts receivable, net	56		61

Receivables from affiliates	1		6

Inventories, net	35		37


Prepaid utility taxes	37		—
Regulatory assets	53		75
Other	5		3
Total current assets	353		326
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,358 and $1,303 as of June 30, 2021 and December 31, 2020, respectively)	3,614		3,475
Deferred debits and other assets
Regulatory assets	422		395



Prepaid pension asset	35		40

Other	49		50
Total deferred debits and other assets	506		485
Total assets(a)	$	4,473	$	4,286

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	178	$	187
Long-term debt due within one year	13		261
Accounts payable	170		177
Accrued expenses	38		46
Payables to affiliates	30		31



Customer deposits	20		23
Regulatory liabilities	39		44
Other	11		11
Total current liabilities	499		780
Long-term debt	1,502		1,152
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	643		624


Non-pension postretirement benefit obligations	14		17

Regulatory liabilities	252		274


Other	47		48
Total deferred credits and other liabilities	956		963
Total liabilities(a)	2,957		2,895
Commitments and contingencies
Shareholder's equity
Common stock	1,574		1,271
Retained (deficit) earnings	(58)		120

Total shareholder's equity	1,516		1,391
Total liabilities and shareholder's equity	$	4,473	$	4,286

__________

(a)ACE’s consolidated total assets include $12 million and $13 million at June 30, 2021 and December 31, 2020, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $11 million and $21 million at June 30, 2021 and December 31, 2020, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 17 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)


	Six Months Ended June 30, 2021
(In millions)	Common Stock		Retained Earnings (Deficit)		Total Shareholder's Equity
Balance, December 31, 2020	$	1,271	$	120	$	1,391
Net income	—		14		14
Common stock dividends	—		(14)		(14)
Contributions from parent	303		—		303
Balance, March 31, 2021	$	1,574	$	120	$	1,694
Net income	—		37		37
Common stock dividends	—		(215)		(215)

Balance, June 30, 2021	$	1,574	$	(58)	$	1,516


	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

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 — Significant Accounting Policies

1. Significant Accounting Policies (All Registrants)

Description of Business (All Registrants)

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

Name of Registrant

Business

Service Territories

Exelon Generation
Company, LLC

Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy, and other energy-related products and services.

Five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions

Commonwealth Edison Company

Purchase and regulated retail sale of electricity

Northern Illinois, including the City of Chicago

Transmission and distribution of electricity to retail customers

PECO Energy Company

Purchase and regulated retail sale of electricity and natural gas

Southeastern Pennsylvania, including the City of Philadelphia (electricity)

Transmission and distribution of electricity and distribution of natural gas to retail customers

Pennsylvania counties surrounding the City of Philadelphia (natural gas)

Baltimore Gas and Electric Company

Purchase and regulated retail sale of electricity and natural gas

Central Maryland, including the City of Baltimore (electricity and natural gas)

Transmission and distribution of electricity and distribution of natural gas to retail customers

Pepco Holdings LLC

Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE

Service Territories of Pepco, DPL, and ACE

Potomac Electric
Power Company

Purchase and regulated retail sale of electricity

District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland

Transmission and distribution of electricity to retail customers

Delmarva Power &
Light Company

Purchase and regulated retail sale of electricity and natural gas

Portions of Delaware and Maryland (electricity)

Transmission and distribution of electricity and distribution of natural gas to retail customers

Portions of New Castle County, Delaware (natural gas)

Atlantic City Electric Company

Purchase and regulated retail sale of electricity

Portions of Southern New Jersey

Transmission and distribution of electricity to retail customers

Basis of Presentation (All Registrants)

This is a combined quarterly report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. 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, 2021 and for the three and six months ended June 30, 2021 and 2020 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

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 — Significant Accounting Policies

disclosed. The December 31, 2020 Consolidated Balance Sheets were derived from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2021. 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.

2. Mergers, Acquisitions, and Dispositions (Exelon and Generation)

CENG Put Option (Exelon and Generation)

Generation owns a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owns the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in Exelon's and Generation's financial statements. See Note 17 — Variable Interest Entities for additional information.

On April 1, 2014, Generation and EDF entered into various agreements including a NOSA, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the amended LLC Operating Agreement, CENG made a $400 million special distribution to EDF and committed to make preferred distributions to Generation until Generation has received aggregate distributions of $400 million plus a return of 8.50% per annum.

Under the terms of the Put Option Agreement, 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. The Put Option Agreement’s terms also provide that in the event the put closing has not been completed prior to the 18-month anniversary of the exercise date, EDF may withdraw its exercise notice. In the event of a withdrawal, EDF retains the right to exercise the put option until the later of June 30, 2022 and 18 months following the date of withdrawal, but in no event later than January 1, 2024. EDF is not entitled to this withdrawal right in the event it breaches any provision of the Put Option Agreement that results in the failure of the put to close on or before the 18-month anniversary of the exercise date.

The Put Option Agreement provides that the purchase price is to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. The third parties determining fair market value of EDF’s 49.99% interest are to take into consideration all rights and obligations under the LLC Operating Agreement and Employee Matters Agreement including but not limited to Generation’s rights with respect to any unpaid aggregate preferred distributions and the related return. As of June 30, 2021, the total unpaid aggregate preferred distributions and related return owed to Generation is $645 million.

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 required approval by the FERC and the NYPSC, which approvals were received on July 30, 2020 and April 15, 2021, respectively. The sale process is currently expected to close in the second half of 2021. EDF has not exercised its right to withdraw the exercise of the put, which right became effective on July 19, 2021.

Agreement for Sale of Generation’s Solar Business (Exelon and Generation)

On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation’s solar business, including 360 MW of generation in operation or under construction across more than 600 sites across the United States. Generation will retain certain solar assets not included in this agreement, primarily Antelope Valley.

Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions which were satisfied in the first quarter of 2021. The sale was completed on March 31, 2021 for a purchase price of $810 million. Generation received cash proceeds of $675 million, net of $125 million long-term debt assumed by the buyer and certain working capital and other post-closing adjustments. Exelon and

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

Note 2 — Mergers, Acquisitions, and Dispositions

Generation recognized a pre-tax gain of $68 million which is included in Gain on sales of assets and businesses in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on the SolGen nonrecourse debt included as part of the transaction.

Agreement for the Sale of a Generation Biomass Facility (Exelon and Generation)

On April 28, 2021, Generation and ReGenerate Energy Holdings, LLC (“ReGenerate”) entered into a purchase agreement, under which ReGenerate agreed to purchase Generation’s interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, Exelon and Generation recorded a pre-tax impairment charge of $140 million within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Completion of the transaction was subject to the satisfaction of various customary closing conditions which were satisfied in the second quarter of 2021. The sale was completed on June 30, 2021 for a net purchase price of $36 million.

3. Regulatory Matters (All Registrants)

As discussed in Note 3 — Regulatory Matters of the Exelon 2020 Form 10-K, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The following discusses developments in 2021 and updates to the 2020 Form 10-K.

Utility Regulatory Matters (Exelon, PHI, and the Utility Registrants)

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2021.

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

Note 3 — Regulatory Matters

Completed Distribution Base Rate Case Proceedings


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement (Decrease) Increase		Approved Revenue Requirement (Decrease) Increase		Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois(a)	April 16, 2020	Electric	$	(11)	$	(14)	8.38	%	December 9, 2020	January 1, 2021
PECO - Pennsylvania	September 30, 2020	Natural Gas	69		29		10.24	%	June 22, 2021	July 1, 2021
BGE - Maryland(b)	May 15, 2020 (amended September 11, 2020)	Electric	203		140		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	108		74		9.65	%
Pepco - District of Columbia(c)	May 30, 2019 (amended June 1, 2020)	Electric	136		109		9.275	%	June 8, 2021	July 1, 2021
Pepco - Maryland(d)	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021

ACE - New Jersey(e)	December 9, 2020 (amended February 26, 2021)	Electric	67		41		9.60	%	July 14, 2021	January 1, 2022

__________

(a)ComEd's 2021 approved revenue requirement reflects an increase of $50 million for the initial year revenue requirement for 2021 and a decrease of $64 million related to the annual reconciliation for 2019. The revenue requirement for 2021 and the revenue requirement for 2019 provide 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 monthly average yields for 30-year treasury bonds plus 580 basis points.

(b)Reflects a three-year cumulative multi-year plan for 2021 through 2023. The MDPSC awarded BGE electric revenue requirement increases of $59 million, $39 million, and $42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million, before offsets, in 2021, 2022, and 2023, respectively. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. However, the MDPSC only utilized the tax benefits to fully offset the increases in 2021 such that customer rates will remain unchanged from 2020 to 2021. The MDPSC has deferred a decision on whether to use certain tax benefits to offset the customer rate increases in 2022 and 2023 and BGE cannot predict the outcome.

(c)Reflects a cumulative multi-year plan with 18-months remaining in 2021 through 2022. The DCPSC awarded Pepco electric incremental revenue requirement increases of $42 million and $67 million, before offsets, for the remainder of 2021 and 2022, respectively. However, the DCPSC utilized the acceleration of refunds for certain tax benefits along with other rate relief to partially offset the customer rate increases by $22 million and $40 million for the remainder of 2021 and 2022, respectively.

(d)Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $21 million, $16 million, and $15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. The MDPSC has deferred decision on whether to use additional tax benefits to offset customer rate increases for periods after March 31, 2022 and Pepco cannot predict the outcome.

(e)Requested and approved increases are before New Jersey sales and use tax. The order allows ACE to retain approximately $11 million of certain tax benefits which will result in a decrease to income tax expense within Exelon's, PHI's, and ACE's Consolidated Statements of Operations and Comprehensive Income in the third quarter of 2021.

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

Note 3 — Regulatory Matters

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

ComEd - Illinois(a)

April 16, 2021

Electric

7.36

Fourth quarter of 2021

PECO - Pennsylvania

March 30, 2021

Electric

246

10.95

Fourth quarter of 2021

DPL - Delaware(b)

March 6, 2020 (amended February 2, 2021)

Electric

10.3

Third quarter of 2021

__________

(a)ComEd's 2022 requested revenue requirement reflects an increase of $40 million for the initial year revenue requirement for 2022 and an increase of $11 million related to the annual reconciliation for 2020. The revenue requirement for 2022 provides for a weighted average debt and equity return on distribution rate base of 5.72%, inclusive of an allowed ROE of 7.36%, reflecting the average monthly yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2020 provides for a weighted average debt and equity return on distribution rate base of 5.69%, inclusive of an allowed ROE of 7.29%, reflecting the average monthly yields for 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points.

(b)The rates went into effect on October 6, 2020, subject to refund.

Transmission Formula Rates

The Utility Registrants' 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 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 BGE, Pepco, DPL, and ACE 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 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, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).

For 2021, the following total increases/(decreases) were included in the Utility Registrants’ electric transmission formula rate updates:


Registrant(a)	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation Increase		Total Revenue Requirement Increase(b)		Allowed Return on Rate Base(c)		Allowed ROE(d)
ComEd	$	33	$	12	$	45	8.20	%	11.50	%
PECO	(2)		26		24		7.37	%	10.35	%
BGE	38		27		65		7.35	%	10.50	%
Pepco	(9)		21		12		7.68	%	10.50	%
DPL	19		33		52		7.20	%	10.50	%
ACE	27		24		51		7.45	%	10.50	%

__________

(a)All rates are effective June 1, 2021 - May 31, 2022, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff.

(b)In 2020, ComEd, BGE, Pepco, DPL, and ACE's transmission revenue requirement included a one-time decrease in accordance with the April 24, 2020 settlement agreement related to excess deferred income taxes which now completed has resulted in an increase to the 2021 transmission revenue requirement. In 2020, PECO's transmission revenue requirement included a one-time decrease in accordance with the December 5, 2019 settlement agreement related to refunds which now completed has resulted in an increase to the 2021 transmission revenue requirement.

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

(d)As part of the FERC-approved settlements of ComEd’s 2007 and PECO's 2017 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

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Note 3 — Regulatory Matters

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.

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 June 1, 2021. The filing establishes the revenue requirement used to set the rates that will take effect in January 2022 after the ICC’s review and approval. The requested revenue requirement update is based on a reconciliation of the 2020 actual costs plus projected 2022 expenditures.


Initial Revenue Requirement Increase		Annual Reconciliation Decrease		Total Revenue Requirement Increase		Requested Return on Rate Base(a)		Requested ROE
$	55	$	(1)	$	54	5.72	%	7.36	%

__________

(a)The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.72% inclusive of an allowed ROE of 7.36%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 2020 reconciliation year, the requested revenue requirement provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.26% inclusive of an allowed ROE of 8.46%, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals.

Maryland Regulatory Matters

Maryland Order Directing the Distribution of Energy Assistance Funds (Exelon, BGE, PHI, Pepco, and DPL). On June 15, 2021, the MDPSC issued an order authorizing the disbursal of funds to utilities in accordance with Maryland COVID-19 relief legislation. Upon receipt, the funds are to be used to reduce or eliminate certain qualifying past-due residential customer receivables. Under this order, BGE, Pepco, and DPL received funds of $50 million, $12 million, and $8 million, respectively, in July 2021.

New Jersey Regulatory Matters

Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed an application with the NJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consisted of estimated costs totaling $220 million with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the installation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and data management systems.

On July 14, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE's smart energy network deployment plan, including cost recovery of the investment costs, incremental O&M expenses, and the unrecovered balance of existing infrastructure through future distribution rates.

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2020, unless noted below. See Note 3 — Regulatory Matters of the Exelon 2020 Form 10-K for additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets increased $116 million primarily due to an increase of $67 million in the Electric Distribution Formula Rate Annual Reconciliations regulatory asset and $85 million in the Energy Efficiency Costs regulatory asset, partially offset by a decrease of $36 million in the renewable energy regulatory asset.

PECO. Regulatory assets increased $95 million primarily due to an increase of $81 million in the Deferred Income Taxes regulatory asset and $12 million in the Vacation Accrual regulatory asset. Regulatory liabilities

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

Note 3 — Regulatory Matters

increased by $85 million primarily due to an increase of $96 million in the Nuclear Decommissioning regulatory liability partially offset by a $13 million decrease in the Electric Energy and Natural Gas Costs regulatory liability.

BGE. Regulatory liabilities decreased $109 million primarily due to a decrease of $111 million in the Deferred Income Taxes regulatory liability.

Pepco. Regulatory liabilities decreased $53 million primarily due to a decrease of $46 million in the Deferred Income Taxes regulatory liability and $14 million in the Transmission Formula Rate regulatory liability partially offset by an increase of $10 million in various regulatory liabilities as a result of the Pepco DC multi-year plan.

DPL. Regulatory liabilities decreased $32 million primarily due to a decrease of $26 million in the Deferred Income Taxes regulatory liability and $9 million in the Transmission Formula Rate regulatory liability.

ACE. Regulatory liabilities decreased $27 million primarily due to a decrease of $20 million in the Deferred Income Taxes regulatory liability and $6 million in the Transmission Formula Rate regulatory liability.

Capitalized Ratemaking Amounts Not Recognized

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 the Utility Registrants' customers.


	Exelon		ComEd(a)		PECO		BGE(b)		PHI		Pepco(c)		DPL(c)		ACE
June 30, 2021	$	48	$	1	$	—	$	41	$	6	$	3	$	3	$	—

December 31, 2020	51		(1)		—		45		7		4		3		—

__________

(a)Reflects ComEd's unrecognized equity returns/(losses) earned/(incurred) 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)

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages

Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. In response to the high demand and significantly reduced total generation on the system, the PUCT directed ERCOT to use an administrative price cap of $9,000 per MWh during firm load shedding events.

During February and March 2021, various parties with differing interests, including generators and retail providers, filed requests with the PUCT to void the PUCT’s orders setting prices at $9,000 per MWh during firm load shedding events. Other requests were made for the PUCT to enforce its order and reduce prices for 33 hours between February 18 and February 19 after firm load shedding ceased, and to cap ancillary services at $9,000 per MWh. On March 2, 2021, a third party filed a notice of appeal in the Court of Appeals for the Third

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

Note 3 — Regulatory Matters

District of Texas challenging the validity of the PUCT’s actions. Generation intervened in that appeal and filed its initial brief on June 2, 2021. On April 19, 2021, Generation filed a declaratory action and request for judicial review of the PUCT’s orders setting prices at $9,000 per MWh in District Court of Travis County, Texas. Generation subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the Court of Appeals in the third party proceeding. On May 17, 2021, Generation amended its petition for declaratory action and request for judicial review pending in the District Court of Travis County, Texas. Exelon and Generation cannot predict the outcome of these proceedings or the financial statement impact.

Due to these events, a number of ERCOT market participants experienced bankruptcies or defaulted on payments to ERCOT, resulting in approximately a $3.0 billion payment shortfall in collections, which is allocated to the remaining ERCOT market participants. As of June 30, 2021, Generation has recorded its portion of this obligation of approximately $17 million on a discounted basis, which is to be paid over a term of 83 years. ERCOT rules historically have limited recovery of default from market participants to $2.5 million per month market-wide. In February 2021, the PUCT gave ERCOT discretion to disregard those rules, but ERCOT has declined to exercise that discretion thus far. On March 8, 2021, a third party filed a notice of appeal in the Court of Appeals for the Third District of Texas challenging the validity of the PUCT's order to ERCOT in February 2021. Generation intervened in that appeal and filed its initial brief on July 7, 2021. On May 7, 2021, Generation filed a declaratory action and request for judicial review of the PUCT's order in the District Court of Travis County, Texas. Generation subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the Court of Appeals in the third party proceeding. Exelon and Generation cannot predict the outcome of these proceedings or the financial statement impact. Additionally, several legislative proposals were introduced in the Texas legislature during February and March 2021 concerning the amount, timing and allocation of recovery of the $3.0 billion shortfall, as well as recovery of other costs associated with the PUCT's directive to set prices at $9,000 per MWh. Two of these proposals were enacted into law in June 2021 and establish financing mechanisms that ERCOT and certain market participants can utilize to fund amounts owed to ERCOT. Exelon and Generation are monitoring the implementation of the legislation, which could result in further adjustment to Generation's portion of the obligation.

In addition, other legislative proposals were introduced in the Texas legislature during February and March 2021 addressing cold-weather preparation for power plants and natural gas production and transportation infrastructure and the market structure for reliability services. The Texas legislature addressed these proposals by enacting a bill with a broad set of market reforms that, among other things, directed the PUCT to establish weatherization standards for electric generators within six months of enactment and gave the PUCT authority to impose administrative penalties if the new proposed standards, once adopted, are not met. On June 9, 2021, PUCT staff issued a request for comments regarding the conditions under which the PUCT should require the operation of electric generation facilities and Generation and other third parties responded on June 23, 2021. Exelon and Generation are monitoring and cannot predict the outcome of this proceeding, which could have a material adverse impact in Exelon’s and Generation’s consolidated financial statements. The legislation also directs the PUCT to evaluate whether additional ancillary services are needed for reliability in the ERCOT power region to provide adequate incentives for dispatchable generation. This evaluation is expected to be taken up by the PUCT later in 2021.

In February 2021, more than 70 local distribution companies (LDCs) and natural gas pipelines in multiple states throughout the mid-continent region, where Generation serves natural gas customers, issued operational flow orders (OFOs), curtailments or other limitations on natural gas transportation or use to manage the operational integrity of the applicable LDC or pipeline system. When in effect, gas transportation or use above these limitations is subject to significant penalties according to the applicable LDCs’ and natural gas pipelines’ tariffs. Gas transportation and supply in many states became restricted due to wells freezing and pipeline compression disruption, while demand was increasing due to the extreme cold temperatures, resulting in extremely high natural gas prices. Due to the extraordinary circumstances, many LDCs and natural gas pipelines have either voluntarily waived or have sought applicable regulatory approvals to waive the tariff penalties associated with the extreme weather event. During March 2021, three natural gas pipelines filed individual petitions with the FERC requesting approval to waive OFO penalties. Generation also filed motions in March 2021 to intervene and filed comments in support of these FERC waiver requests. On March 25, 2021, the FERC issued an order on one of the petitions approving a pipeline’s request for a limited waiver of penalties for February 15, 2021. On April 23, 2021, Generation and several other entities filed a request for rehearing and a complaint requesting that FERC expand the order to include additional days of the weather event in February, from February 16 through February 19, 2021. During April 2021, the FERC issued orders on the remaining petitions approving the requests to waive the penalties. During May 2021, an LDC filed a motion with the Kansas Corporation Commission (KCC)

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

Note 3 — Regulatory Matters

requesting the KCC to grant a waiver from the tariff and allow the LDC to reduce the amounts assessed by permitting the removal of a multiplier from the penalty calculation. Exelon and Generation cannot predict the outcome of the pending FERC complaint proceeding, the KCC proceeding, or the determinations made by the LDCs and natural gas pipelines.

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. On March 19, 2021, a three-judge panel of the Superior Court of New Jersey Appellate Division unanimously affirmed the NJBPU’s April 2019 order awarding ZECs for the first eligibility period. On April 8, 2021, New Jersey Rate Counsel filed a notice asking the New Jersey Supreme Court to hear the appeal of the Superior Court’s order. On July 9, 2021, the New Jersey Supreme Court declined to hear the appeal. On October 1, 2020, PSEG and Generation filed applications seeking ZECs for the second eligibility period (June 2022 through May 2025). On April 27, 2021, the NJBPU approved the award of ZECs to Salem 1 and Salem 2 for the second eligibility period. On May 11, 2021, the New Jersey Rate Counsel appealed the April 27, 2021 decision to the Superior Court of New Jersey Appellate Division. Exelon and Generation cannot predict the outcome of this proceeding. See Note 7 — Early Plant Retirements for additional information related to Salem.

New England Regulatory Matters

Mystic Units 8 & 9 and Everett Marine Terminal Cost of Service Agreement. On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. 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 & 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service compensation, 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 adjacent Everett Marine Terminal acquired by Generation in October 2018. Those adjustments were reflected in a compliance filing made on 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 15, 2021, FERC issued an order establishing the ROE to be used in the cost of service agreement for Mystic 8 and 9 at 9.33%.

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. In addition, several parties filed protests to a compliance filing by Generation on September 15, 2020, taking issue with how gross plant in-service was calculated, and Generation filed an answer to the protests on October 21, 2020. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of service provisions. Several parties appealed the December 21, 2020 order to the U.S. Court of Appeals for the D.C. Circuit and that appeal was consolidated with appeals of orders issued December 20, 2018 and July 17, 2020 in the Mystic proceeding. The briefing schedule for the consolidated appeal has not yet been set.

On February 25, 2021, Mystic made its filing to comply with the December 21, 2020 order. On April 26, 2021, FERC rejected Mystic’s language and directed another compliance filing relating to the claw back provision language, which only applies if Mystic 8 and 9 were to continue operation after the conclusion of the cost-of-service period. FERC’s April 26, 2021 order also accepted in part and rejected in part Mystic’s September 15, 2020 compliance filing. It directed a further compliance filing in 60 days consistent with the information provided in Mystic’s October 21, 2020 answer to protests, which Mystic filed on June 2, 2021.

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Note 3 — Regulatory Matters

On August 25, 2020, a group of New England generators filed a complaint against Generation seeking to extend the scope of the claw back provision in the cost-of-service agreement, whereby Generation would refund certain amounts recovered during the term of the cost of service if it returns to market afterwards. On April 15, 2021 FERC dismissed the complaint.

On February 16, 2021, Generation filed an unopposed motion to voluntarily dismiss an appeal filed with the U.S. Court of Appeals for the D.C. Circuit stemming from a June 2020 complaint filed with the FERC against ISO-NE over failures to follow its tariff in evaluating Mystic for transmission security for the 2024 to 2025 Capacity Commitment Period, which was granted on February 18, 2021.

See Note 7 — Early Plant Retirements for additional information on the impacts of Generation’s August 2020 decision to retire Mystic Units 8 & 9 upon expiration of the cost of service agreement.

Federal Regulatory Matters

PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a 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.

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 proposed tariff language interpreting and implementing FERC's directives, and proposed a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing.

On April 16, 2020, FERC issued an order largely denying most requests for rehearing of FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing which PJM submitted on June 1, 2020.

On October 15, 2020, FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting PJM’s two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, FERC also accepted PJM’s proposal to condense the schedule of activities leading up to the next capacity auction. A number of parties, including Exelon, have filed petitions for review of FERC's orders in this proceeding, which remain pending before the Court of Appeals for the District of Columbia Circuit.

In November 2020, PJM announced that it will conduct its next capacity auction beginning on May 19, 2021 and ending on May 25, 2021 and will post the results on June 2, 2021. PJM conducted the auction as scheduled and, because neither Illinois nor New Jersey implemented an FRR program in their PJM zones, the MOPR applied in the 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. The MOPR prevented Quad Cities from clearing in the capacity auction.

At the direction of the PJM Board of Managers, PJM and its stakeholders are considering MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Regulatory Matters

programs which PJM filed at FERC on July 30, 2021. Exelon cannot predict whether or when such changes can be implemented.

On February 20, 2020, FERC issued an order rejecting requests to expand NYISO’s version of the MOPR (referred to as buyer-side mitigation rules) beyond its current limited applicability to certain resources in downstate. However, on October 14, 2020, two natural gas-fired generators in New York filed a complaint at FERC seeking to expand the MOPR in NYISO to apply to all resources, new and existing, across the entire NYISO market. Exelon is strenuously opposing expansion of FERC’s MOPR policies in the NYISO market. While it is too early in the proceeding to predict its outcome and there are significant differences between the NYISO and PJM markets that would justify a different result, if FERC follows its MOPR precedent in PJM and applies the MOPR in NYISO broadly as requested in the complaint, Generation’s facilities in NYISO that are receiving ZEC compensation may be at increased risk of not clearing the capacity auction.

If Generation’s state-supported nuclear plants in PJM or NYISO 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 had been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.

On April 27, 2018, MDE issued its 401 Certification for Conowingo. 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.

On March 19, 2021, FERC issued a new 50-year license for Conowingo, effective March 1, 2021. FERC adopted the Proposed License Articles into the new license only making modifications it deemed necessary to allow FERC to enforce the Proposed License Articles. Consistent with the Offer of Settlement, FERC found that MDE waived its 401 Certification. On April 19, 2021, a few environmental groups filed with FERC a petition for rehearing requesting that FERC reconsider the issuance of the new Conowingo license, which was denied by operation of law on May 20, 2021. On June 17, 2021, the petitioners appealed FERC’s ruling to the United States Court of Appeals. On July 15, 2021, FERC issued an order addressing the arguments raised on rehearing, affirming the determinations of its March 19, 2021 order. Generation cannot predict the outcome of this proceeding.

4. Revenue from Contracts with Customers (All Registrants)

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

See Note 4 — Revenue from Contracts with Customers of the Exelon 2020 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.

Contract Balances (All Registrants)

Contract Assets

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

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

Note 4 — Revenue from Contracts with Customers

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.

The following table provides a rollforward of the contract assets reflected in Exelon's and Generation's Consolidated Balance Sheets for the three and six months ended June 30, 2021 and 2020. The Utility Registrants do not have any contract assets.



	Exelon		Generation
Balance as of December 31, 2020	$	144	$	144
Amounts reclassified to receivables	(16)		(16)
Revenues recognized	13		13
Amounts previously held-for-sale	12		12
Balance as of March 31, 2021	153		153
Amounts reclassified to receivables	(12)		(12)
Revenues recognized	9		9

Balance as of June 30, 2021	$	150	$	150


	Exelon		Generation
Balance as of December 31, 2019	$	174	$	174
Amounts reclassified to receivables	(19)		(19)
Revenues recognized	17		17

Balance as of March 31, 2020	172		172
Amounts reclassified to receivables	(26)		(26)
Revenues recognized	13		13
Balance as of June 30, 2020	$	159	$	159

Contract Liabilities

The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities within Other current liabilities and Other noncurrent liabilities within the Registrants' Consolidated Balance Sheets.

For Generation, these contract liabilities primarily relate to upfront consideration received or due for equipment service plans, and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation.

For PHI, Pepco, DPL, and ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement with an unrelated owner and manager of communication infrastructure. The revenue attributable to this arrangement will be recognized as operating revenue over the 35 years under the collaborative arrangement.

The following table provides a rollforward of the contract liabilities reflected in Exelon's, Generation's, PHI's, Pepco's, DPL's, and ACE's Consolidated Balance Sheets for the three and six months ended June 30, 2021 and 2020. As of June 30, 2021 and December 31, 2020, ComEd's, PECO's, and BGE's contract liabilities were immaterial.

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

Note 4 — Revenue from Contracts with Customers



	Exelon		Generation		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	151	$	84	$	118	$	94	$	12	$	12
Consideration received or due	20		31		—		—		—		—
Revenues recognized	(27)		(64)		(2)		(2)		—		—
Amounts previously held-for-sale	3		3		—		—		—		—
Balance as of March 31, 2021	147		54		116		92		12		12
Consideration received or due	17		39		—		—		—		—
Revenues recognized	(32)		(68)		(3)		(1)		(1)		(1)

Balance as of June 30, 2021	$	132	$	25	$	113	$	91	$	11	$	11


	Exelon		Generation		PHI		Pepco		DPL		ACE
Balance as of December 31, 2019	$	33	$	71	$	—	$	—	$	—	$	—
Consideration received or due	20		55		—		—		—		—
Revenues recognized	(24)		(70)		—		—		—		—
Balance as of March 31, 2020	29		56		—		—		—		—
Consideration received or due	13		34		—		—		—		—
Revenues recognized	(22)		(63)		—		—		—		—
Balance as of June 30, 2020	$	20	$	27	$	—	$	—	$	—	$	—

The following table reflects revenues recognized in the three and six months ended June 30, 2021 and 2020, which were included in contract liabilities at December 31, 2020 and 2019, respectively:


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Exelon	$	17	$	14	$	34	$	23
Generation	41		42		79		61
PHI	3		—		5		—
Pepco	1		—		3		—
DPL	1		—		1		—
ACE	1		—		1		—

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, 2021. 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.


	2021		2022		2023		2024		2025 and thereafter		Total
Exelon	$	149	$	100	$	46	$	31	$	180	$	506
Generation	223		146		54		29		94		546
PHI	5		8		8		6		86		113
Pepco	3		6		6		5		71		91
DPL	1		1		1		—		8		11
ACE	1		1		1		1		7		11

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

Note 4 — Revenue from Contracts with Customers

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 5 — Segment Information for the presentation of the Registrant's revenue disaggregation.

5. Segment Information (All Registrants)

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

Exelon has eleven reportable segments, which include Generation's five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL, and ACE based on net income.

The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation’s five reportable segments are as follows:

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

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

•New York represents operations within NYISO.

•ERCOT represents operations within Electric Reliability Council of Texas.

•Other Power Regions:

•New England represents the operations within ISO-NE.

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

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

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

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

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

Note 5 — Segment Information

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, 2021 and 2020 is as follows:

Three Months Ended June 30, 2021 and 2020



	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2021
Competitive businesses electric revenues	$	3,747	$	—	$	—	$	—	$	—	$	—	$	(250)	$	3,497
Competitive businesses natural gas revenues	507		—		—		—		—		—		—		507
Competitive businesses other revenues	(101)		—		—		—		—		—		(3)		(104)
Rate-regulated electric revenues	—		1,517		610		558		1,113		—		(11)		3,787
Rate-regulated natural gas revenues	—		—		83		124		24		—		(3)		228
Shared service and other revenues	—		—		—		—		3		524		(527)		—
Total operating revenues	$	4,153	$	1,517	$	693	$	682	$	1,140	$	524	$	(794)	$	7,915
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


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Intersegment revenues(c):
2021	$	254	$	5	$	2	$	7	$	4	$	522	$	(794)	$	—
2020	271		11		2		4		3		470		(760)		1
Depreciation and amortization:

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

Note 5 — Segment Information


2021	$	930	$	296	$	87	$	141	$	194	$	18	$	—	$	1,666
2020	300		274		88		129		191		19		—		1,001
Operating expenses:
2021	$	4,469	$	1,196	$	552	$	620	$	955	$	537	$	(768)	$	7,561
2020	3,547		1,345		618		573		956		478		(748)		6,769
Interest expense, net:
2021	$	76	$	98	$	42	$	34	$	67	$	79	$	—	$	396
2020	87		98		36		32		67		107		—		427
Income (loss) before income taxes:
2021	$	124	$	238	$	106	$	37	$	138	$	(92)	$	—	$	551
2020	860		(15)		32		17		7		(108)		1		794
Income Taxes:
2021	$	110	$	46	$	2	$	(8)	$	(3)	$	(73)	$	—	$	74
2020	329		46		(7)		(22)		(87)		(40)		—		219
Net income (loss):
2021	$	13	$	192	$	104	$	45	$	141	$	(19)	$	—	$	476
2020	529		(61)		39		39		94		(67)		1		574
Capital Expenditures:
2021	$	337	$	549	$	282	$	284	$	433	$	15	$	—	$	1,900
2020	372		523		253		265		310		34		—		1,757

(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 18— 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 19— Related Party Transactions for additional information on intersegment revenues.

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

Note 5 — Segment Information

PHI:



	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2021
Rate-regulated electric revenues	$	523	$	274	$	319	$	—	$	(3)	$	1,113
Rate-regulated natural gas revenues	—		24		—		—		—		24
Shared service and other revenues	—		—		—		95		(92)		3
Total operating revenues	$	523	$	298	$	319	$	95	$	(95)	$	1,140
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
Intersegment revenues(c):
2021	$	1	$	2	$	1	$	95	$	(95)	$	4
2020	1		2		1		97		(98)		3
Depreciation and amortization:
2021	$	96	$	51	$	40	$	7	$	—	$	194
2020	92		47		44		8		—		191
Operating expenses:
2021	$	429	$	255	$	269	$	97	$	(95)	$	955
2020	436		263		258		97		(98)		956
Interest expense, net:
2021	$	35	$	16	$	14	$	2	$	—	$	67
2020	34		15		15		3		—		67
Income (loss) before income taxes:
2021	$	72	$	31	$	36	$	(1)	$	—	$	138
2020	33		(9)		(15)		(2)		—		7
Income Taxes:
2021	$	(3)	$	1	$	(1)	$	—	$	—	$	(3)
2020	(24)		(28)		(33)		(2)		—		(87)
Net income (loss):
2021	$	75	$	30	$	37	$	(1)	$	—	$	141
2020	57		19		18		—		—		94
Capital Expenditures:
2021	$	219	$	99	$	116	$	(1)	$	—	$	433
2020	144		89		77		—		—		310

__________

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

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

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

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

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, 2021
	Revenues from external customers(a)						Intersegment Revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	1,062	$	24	$	1,086	$	5	$	1,091
Midwest	975		(13)		962		—		962
New York	376		5		381		—		381
ERCOT	179		92		271		4		275
Other Power Regions	921		126		1,047		(9)		1,038
Total Competitive Businesses Electric Revenues	3,513		234		3,747		—		3,747
Competitive Businesses Natural Gas Revenues	253		254		507		—		507
Competitive Businesses Other Revenues(c)	107		(208)		(101)		—		(101)
Total Generation Consolidated Operating Revenues	$	3,873	$	280	$	4,153	$	—	$	4,153


	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

__________

(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 losses of $239 million and gains of $21 million in 2021 and 2020, respectively, and elimination of intersegment revenues.

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

Note 5 — Segment Information

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


	Three Months Ended June 30, 2021						Three Months Ended June 30, 2020
	RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	567	$	5	$	572	$	516	$	9	$	525
Midwest	658		—		658		702		1		703
New York	289		3		292		243		3		246
ERCOT	80		3		83		92		5		97
Other Power Regions	157		(21)		136		181		(24)		157
Total Revenues net of purchased power and fuel expense for Reportable Segments	1,751		(10)		1,741		1,734		(6)		1,728
Other(b)	455		10		465		204		6		210
Total Generation Revenues net of purchased power and fuel expense	$	2,206	$	—	$	2,206	$	1,938	$	—	$	1,938

__________

(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 $314 million and gains of $85 million in 2021 and 2020, respectively and the elimination of intersegment RNF.

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

Note 5 — Segment Information

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


	Three Months Ended June 30, 2021
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	759	$	383	$	299	$	537	$	223	$	147	$	167
Small commercial & industrial	377		99		60		124		32		46		46
Large commercial & industrial	138		59		108		257		188		22		47
Public authorities & electric railroads	11		8		7		17		10		3		4
Other(a)	214		54		87		139		50		46		43
Total rate-regulated electric revenues(b)	$	1,499	$	603	$	561	$	1,074	$	503	$	264	$	307
Rate-regulated natural gas revenues
Residential	$	—	$	55	$	81	$	12	$	—	$	12	$	—
Small commercial & industrial	—		22		13		6		—		6		—
Large commercial & industrial	—		—		27		1		—		1		—
Transportation	—		5		—		3		—		3		—
Other(c)	—		1		6		2		—		2		—
Total rate-regulated natural gas revenues(d)	$	—	$	83	$	127	$	24	$	—	$	24	$	—
Total rate-regulated revenues from contracts with customers	$	1,499	$	686	$	688	$	1,098	$	503	$	288	$	307

Other revenues
Revenues from alternative revenue programs	$	9	$	7	$	(10)	$	41	$	19	$	10	$	12
Other rate-regulated electric revenues(e)	9		—		3		1		1		—		—
Other rate-regulated natural gas revenues(e)	—		—		1		—		—		—		—

Total other revenues	$	18	$	7	$	(6)	$	42	$	20	$	10	$	12
Total rate-regulated revenues for reportable segments	$	1,517	$	693	$	682	$	1,140	$	523	$	298	$	319

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information


	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

__________

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

(b)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•$5 million, $11 million at ComEd

•$1 million, $1 million at PECO

•$4 million, $3 million at BGE

•$4 million, $3 million at PHI

•$1 million, $1 million at Pepco

•$2 million, $2 million at DPL

•$1 million, $1 million at ACE

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

(d)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•less than $1 million at PECO both 2021 and 2020

•$3 million, $1 million at BGE

(e)Includes late payment charge revenues.

Six Months Ended June 30, 2021 and 2020


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2021
Competitive businesses electric revenues	$	7,935	$	—	$	—	$	—	$	—	$	—	$	(546)	$	7,389

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Competitive businesses natural gas revenues	1,833		—		—		—		—		—		—		1,833
Competitive businesses other revenues	(56)		—		—		—		—		—		(1)		(57)
Rate-regulated electric revenues	—		3,052		1,271		1,190		2,283		—		(21)		7,775
Rate-regulated natural gas revenues	—		—		311		466		95		—		(7)		865
Shared service and other revenues	—		—		—		—		6		1,013		(1,019)		—
Total operating revenues	$	9,712	$	3,052	$	1,582	$	1,656	$	2,384	$	1,013	$	(1,594)	$	17,805
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

Intersegment revenues(c):
2021	$	549	$	11	$	4	$	13	$	7	$	1,010	$	(1,594)	$	—
2020	601		16		4		10		7		949		(1,585)		2
Depreciation and amortization:
2021	$	1,869	$	589	$	173	$	293	$	404	$	35	$	—	$	3,363
2020	604		547		173		272		385		42		—		2,023
Operating expenses:
2021	$	11,141	$	2,406	$	1,231	$	1,372	$	2,013	$	1,029	$	(1,549)	$	17,643
2020	7,947		2,497		1,242		1,263		1,955		958		(1,564)		14,298
Interest expense, net:
2021	$	148	$	193	$	80	$	67	$	134	$	161	$	—	$	783
2020	197		192		71		64		134		179		—		837

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Income (loss) before income taxes:
2021	$	(823)	$	475	$	283	$	233	$	273	$	(174)	$	1	$	268
2020	313		189		187		237		126		(175)		2		879
Income Taxes:
2021	$	(70)	$	85	$	12	$	(21)	$	5	$	44	$	—	$	55
2020	(59)		82		9		18		(76)		(49)		—		(75)
Net income (loss):
2021	$	(756)	$	390	$	271	$	254	$	269	$	(218)	$	1	$	211
2020	368		107		178		219		202		(126)		2		950
Capital Expenditures:
2021	$	719	$	1,162	$	577	$	620	$	889	$	73	$	—	$	4,040
2020	930		1,029		512		548		686		68		—		3,773
Total assets:
June 30, 2021	$	45,821	$	35,324	$	13,491	$	12,186	$	24,235	$	8,507	$	(10,168)	$	129,396
December 31, 2020	48,094		34,466		12,531		11,650		23,736		9,005		(10,165)		129,317

__________

(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 18 — 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 19 — Related Party Transactions for additional information on intersegment revenues.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

PHI:


	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2021
Rate-regulated electric revenues	$	1,076	$	585	$	629	$	—	$	(7)	$	2,283
Rate-regulated natural gas revenues	—		95		—		—		—		95
Shared service and other revenues	—		—		—		189		(183)		6
Total operating revenues	$	1,076	$	680	$	629	$	189	$	(190)	$	2,384
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
Intersegment revenues(c):
2021	$	3	$	4	$	1	$	189	$	(190)	$	7
2020	3		4		1		189		(190)		7
Depreciation and amortization:
2021	$	199	$	104	$	87	$	14	$	—	$	404
2020	186		94		86		19		—		385
Operating expenses:
2021	$	895	$	564	$	552	$	192	$	(190)	$	2,013
2020	899		547		509		190		(190)		1,955
Interest expense, net:
2021	$	69	$	30	$	29	$	6	$	—	$	134
2020	68		31		29		6		—		134
Income (loss) before income taxes:
2021	$	137	$	92	$	50	$	(6)	$	—	$	273
2020	90		44		(1)		(7)		—		126
Income Taxes:
2021	$	3	$	6	$	(1)	$	(3)	$	—	$	5
2020	(19)		(20)		(32)		(5)		—		(76)
Net income (loss):
2021	$	134	$	86	$	51	$	(2)	$	—	$	269
2020	109		64		31		(2)		—		202
Capital Expenditures:
2021	$	439	$	211	$	239	$	—	$	—	$	889
2020	324		184		178		—		—		686
Total assets:
June 30, 2021	$	9,588	$	5,229	$	4,473	$	5,014	$	(69)	$	24,235
December 31, 2020	9,264		5,140		4,286		5,079		(33)		23,736

__________

(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 18 — Supplemental Financial Information for additional information on total utility taxes.

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

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

Competitive Business Revenues (Generation):



	Six Months Ended June 30, 2021
	Revenues from external customers(a)						Intersegment Revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	2,233	$	11	$	2,244	$	11	$	2,255
Midwest	1,983		(24)		1,959		1		1,960
New York	759		(40)		719		—		719
ERCOT	533		(10)		523		9		532
Other Power Regions	2,095		395		2,490		(21)		2,469
Total Competitive Businesses Electric Revenues	7,603		332		7,935		—		7,935
Competitive Businesses Natural Gas Revenues	1,117		716		1,833		—		1,833
Competitive Businesses Other Revenues(c)	195		(251)		(56)		—		(56)
Total Generation Consolidated Operating Revenues	$	8,915	$	797	$	9,712	$	—	$	9,712



	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

__________

(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 losses of $323 million and gains of $200 million in 2021 and 2020, respectively, and elimination of intersegment revenues.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

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



	Six Months Ended June 30, 2021						Six Months Ended June 30, 2020
	RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	1,130	$	11	$	1,141	$	1,074	$	18	$	1,092
Midwest	1,359		1		1,360		1,431		(4)		1,427
New York	531		5		536		433		7		440
ERCOT	(957)		(145)		(1,102)		168		9		177
Other Power Regions	409		(56)		353		355		(43)		312
Total Revenues net of purchased power and fuel expense for Reportable Segments	2,472		(184)		2,288		3,461		(13)		3,448
Other(b)	683		184		867		506		13		519
Total Generation Revenues net of purchased power and fuel expense	$	3,155	$	—	$	3,155	$	3,967	$	—	$	3,967

__________

(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. Primarily includes:

•unrealized mark-to-market gains of $489 million and gains of $218 million in 2021 and 2020, respectively;

•accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $106 million in 2021; and

• the elimination of intersegment RNF.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

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



	Six Months Ended June 30, 2021
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	1,502	$	816	$	662	$	1,142	$	476	$	337	$	329
Small commercial & industrial	744		199		129		242		65		92		85
Large commercial & industrial	271		116		213		505		372		43		90
Public authorities & electric railroads	22		17		13		30		16		7		7
Other(a)	433		106		165		283		101		87		95
Total rate-regulated electric revenues(b)	$	2,972	$	1,254	$	1,182	$	2,202	$	1,030	$	566	$	606
Rate-regulated natural gas revenues
Residential	$	—	$	215	$	297	$	57	$	—	$	57	$	—
Small commercial & industrial	—		81		48		24		—		24		—
Large commercial & industrial	—		—		81		3		—		3		—
Transportation	—		12		—		8		—		8		—
Other(c)	—		3		36		2		—		3		—
Total rate-regulated natural gas revenues(d)	$	—	$	311	$	462	$	94	$	—	$	95	$	—
Total rate-regulated revenues from contracts with customers	$	2,972	$	1,565	$	1,644	$	2,296	$	1,030	$	661	$	606

Other revenues
Revenues from alternative revenue programs	$	64	$	17	$	8	$	88	$	46	$	19	$	23
Other rate-regulated electric revenues(e)	16		—		3		—		—		—		—
Other rate-regulated natural gas revenues(e)	—		—		1		—		—		—		—

Total other revenues	$	80	$	17	$	12	$	88	$	46	$	19	$	23
Total rate-regulated revenues for reportable segments	$	3,052	$	1,582	$	1,656	$	2,384	$	1,076	$	680	$	629

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information



	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		30		17		6		7
Other(a)	430		113		154		333		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

__________

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

(b)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•$11 million, $16 million at ComEd

•$3 million, $3 million at PECO

•$5 million, $6 million at BGE

•$7 million, $7 million at PHI

•$3 million, $3 million at Pepco

•$4 million, $4 million at DPL

•$1 million, $1 million at ACE

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

(d)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•$1 million, less than $1 million at PECO

•$7 million, $4 million at BGE

(e)Includes late payment charge revenues.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

6. 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, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of March 31, 2021	$	442	$	65	$	103	$	130	$	43	$	101	$	41	$	25	$	35
Plus: Current period provision for expected credit losses	(29)		13		(9)		(14)		(14)		(5)		(1)		(5)		1
Less: Write-offs, net of recoveries(a)	18		3		5		5		2		3		2		1		—

Balance as of June 30, 2021	$	395	$	75	$	89	$	111	$	27	$	93	$	38	$	19	$	36

	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

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable


















	Six Months Ended June 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	366	$	32	$	97	$	116	$	35	$	86	$	32	$	22	$	32
Plus: Current period provision for expected credit losses(c)	75		47		12		6		(5)		15		10		1		4
Less: Write-offs, net of recoveries(a)	46		4		20		11		3		8		4		4		—

Balance as of June 30, 2021	$	395	$	75	$	89	$	111	$	27	$	93	$	38	$	19	$	36

	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.

(c)For Generation, primarily relates to the impacts of the February 2021 extreme cold weather event. See Note 3 — Regulatory Matters for additional information.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

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


	Three Months Ended June 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of March 31, 2021	$	79	$	—	$	22	$	11	$	9	$	37	$	15	$	10	$	12
Plus: Current period provision for expected credit losses	(4)		1		(3)		(3)		—		1		1		(1)		1
Less: Write-offs, net of recoveries(a)	3		—		1		1		1		—		—		—		—
Balance as of June 30, 2021	$	72	$	1	$	18	$	7	$	8	$	38	$	16	$	9	$	13

	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, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	71	$	—	$	21	$	8	$	9	$	33	$	13	$	9	$	11
Plus: Current period provision for expected credit losses	6		1		(2)		1		1		5		3		—		2
Less: Write-offs, net of recoveries(a)	5		—		1		2		2		—		—		—		—
Balance as of June 30, 2021	$	72	$	1	$	18	$	7	$	8	$	38	$	16	$	9	$	13

	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.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

Unbilled Customer Revenue (All Registrants)

The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of June 30, 2021 and December 31, 2020.


	Unbilled customer revenues(a)
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2021	$	1,029	$	329	$	263	$	131	$	119	$	187	$	90	$	39	$	58
December 31, 2020	998		258		218		147		197		178		87		62		29

__________

(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 had a maximum funding limit of $750 million and was scheduled to expire on April 7, 2021, unless renewed by the mutual consent of the parties in accordance with its terms. The Facility was renewed on March 29, 2021. The Facility term was extended through March 29, 2024, unless further renewed by the mutual consent of the parties, and the maximum funding limit was increased to $900 million. 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 Sheets.

The Facility requires the balance of eligible receivables to be maintained at or above the balance of cash proceeds received from the Purchasers. To the extent the eligible receivables decrease below such balance, Generation is required to repay cash to the Purchasers. When eligible receivables exceed cash proceeds, Generation has the ability to increase the cash received up to the maximum funding limit. These cash inflows and outflows impact the DPP.

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.

During the first quarter of 2021, Generation received additional cash of $250 million from the Purchasers for the remaining available funding in the Facility.

Additionally, during the first quarter of 2021, Generation received cash of approximately $150 million from the Purchasers in connection with the increased funding limit at the time of the Facility renewal.

During the second quarter of 2021, Generation returned cash of $50 million to the Purchasers due to the eligible receivables decreasing temporarily. Subsequently, in the second quarter, Generation received cash of $50 million from the Purchasers as a result of an increase in the eligible receivable balance. The $50 million cash outflow and inflow is included in the Collection of DPP line within Cash flows from investing activities in Exelon’s and Generation’s Consolidated Statements of Cash Flows.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

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


	June 30, 2021		December 31, 2020
Derecognized receivables transferred at fair value	$	1,274	$	1,139
Cash proceeds received	900		500
DPP	374		639


	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Loss on sale of receivables(a)	$	8	$	15	$	25	$	15

__________

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


	Six Months Ended June 30,
	2021		2020
Proceeds from new transfers(a)	$	2,689	$	927
Cash collections received on DPP and reinvested in the Facility(b)	1,809		1,102
Cash collections reinvested in the Facility	4,498		2,029

__________

(a)Customer accounts receivable sold into the Facility were $4,647 million and $2,032 million for the six months ended June 30, 2021 and June 30, 2020, respectively

(b)Does not include the $400 million in cash proceeds received from the Purchasers in the first quarter of 2021.

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 recognizes 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 14 — Fair Value of Financial Assets and Liabilities and Note 17 — Variable Interest Entities for additional information.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

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, Delaware, 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.


	Six Months Ended June 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total receivables purchased	$	1,823	$	—	$	485	$	507	$	343	$	503	$	310	$	103	$	90
Total receivables sold	92		107		—		—		—		—		—		—		—

Related party transactions:
Receivables purchased from Generation	—		—		—		—		15		—		—		—		—
Receivables sold to the Utility Registrants	—		15		—		—		—		—		—		—		—



	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		—		—		—		—		—		—		—

7. 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.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Early Plant Retirements

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 TMI 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, in addition to FitzPatrick, would 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 PJM adopts further changes to the MOPR or Illinois and New Jersey implement an FRR mechanism under which the Generation plants in these states would be removed from PJM’s capacity auction. At the direction of the PJM Board of Managers, PJM and its stakeholders are considering MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs, which PJM filed at FERC on July 30, 2021. See Note 3 - Regulatory Matters for additional information on the New Jersey ZEC program, Note 3 — Regulatory Matters of the 2020 Form 10-K for additional information on the Illinois ZES, New York CES and FERC's December 19, 2019 order on the MOPR in PJM. We cannot predict whether or when FERC will act on PJM's proposed changes.

On August 27, 2020, Generation announced that it intends to permanently cease generation operations at Byron in September 2021 and at Dresden in November 2021. The current NRC licenses for Byron Units 1 and 2 expire in 2044 and 2046, respectively, and the licenses for Dresden Units 2 and 3 expire in 2029 and 2031, respectively. Neither of these nuclear plants cleared in PJM’s capacity auction for the 2022-2023 planning year held in May 2021.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Early Plant Retirements

Generation’s Braidwood and LaSalle nuclear plants in Illinois are also showing increased signs of economic distress, 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. While all of Braidwood's and LaSalle's capacity did clear in the 2022-2023 planning year auction, Generation has become increasingly concerned about the economic viability of these plants as well in a landscape where energy market prices remain depressed and energy market rules remain fatally flawed.

As a result of the decision to early retire Byron and Dresden, Exelon and Generation recognized certain one-time charges in the third and fourth quarters of 2020 related to materials and supplies inventory reserve adjustments, employee-related costs including severance benefit costs further discussed below, and construction work-in-progress impairments, among other items. In addition, as a result of the decisions to early retire Byron and Dresden, there are ongoing annual financial impacts stemming from shortening the expected economic useful lives of these nuclear plants primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and changes in ARO accretion expense associated with the changes in decommissioning timing and cost assumptions to reflect an earlier retirement date. The total impact for the three and six months ended June 30, 2021 on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income is summarized in the table below.


Income statement expense (pre-tax)	Three Months Ended June 30, 2021(a)		Six Months Ended June 30, 2021(a)
Depreciation and amortization
Accelerated depreciation(a)	$	611	$	1,230
Accelerated nuclear fuel amortization	52		106
Operating and maintenance
Other charges	2		4

Contractual offset(b)	(166)		(391)
Total	$	499	$	949

_________

(a)Includes the accelerated depreciation of plant assets including any ARC.

(b)Reflects contractual offset for ARO accretion and ARC depreciation and excludes any changes in earnings in the NDT funds. Decommissioning-related impacts were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activities result in a regulatory liability at ComEd. The offset resulted in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 8 - Nuclear Decommissioning for additional information.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Early Plant Retirements

Severance benefit costs will be provided to employees impacted by the early retirements of Byron and Dresden, to the extent they are not redeployed to other nuclear plants. In 2020, Exelon and Generation recorded estimated severance expense of $81 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. The severance liability was $81 million as of June 30, 2021 on Exelon's and Generation's Consolidated Balance Sheets. The final amount of severance benefit costs will depend on the specific employees severed.

The following table provides the balance sheet amounts as of June 30, 2021 for Exelon's and Generation's significant assets and liabilities associated with the Braidwood and LaSalle nuclear plants. Current depreciation provisions are based on the estimated useful lives of these nuclear generating stations, which reflect the first renewal of the operating licenses.


	Braidwood		LaSalle		Total
Asset Balances
Materials and supplies inventory, net	$	82	$	105	$	187
Nuclear fuel inventory, net	196		244		440
Completed plant, net	1,380		1,610		2,990
Construction work in progress	30		12		42
Liability Balances
Asset retirement obligation	(585)		(975)		(1,560)

NRC License First Renewal Term	2046 (Unit 1)		2042 (Unit 1)
	2047 (Unit 2)		2043 (Unit 2)

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.

Other Generation

In March 2018, Generation notified ISO-NE of its plans to early retire, among other assets, the Mystic Generating Station's units 8 and 9 (Mystic 8 and 9) absent regulatory reforms to properly value reliability and regional fuel security. Thereafter, ISO-NE identified Mystic 8 and 9 as being needed to ensure fuel security for the region and entered into a cost of service agreement with these two units for the period between June 1, 2022 - May 31, 2024. The agreement was approved by the FERC in December 2018.

On June 10, 2020, Generation filed a complaint with FERC against ISO-NE stating that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic 8 and 9 for transmission security for the 2024 to 2025 Capacity Commitment Period and that the modifications that ISO-NE made to its unfiled planning procedures to avoid retaining Mystic 8 and 9 should have been filed with FERC for approval. On August 17, 2020, FERC issued an order denying the complaint. As a result, on August 20, 2020, Exelon determined that Generation will permanently cease generation operations at Mystic 8 and 9 at the expiration of the cost of service commitment in May 2024. See Note 3 — Regulatory Matters for additional discussion of Mystic’s cost of service agreement.

As a result of the decision to early retire Mystic 8 and 9, there are financial impacts stemming from shortening the expected economic useful life of Mystic 8 and 9 primarily related to accelerated depreciation of plant assets. Exelon and Generation recorded incremental Depreciation and amortization expense of $21 million and $41 million for the three and six months ended June 30, 2021, respectively.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 8 — Nuclear Decommissioning

8. 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, 2020 to June 30, 2021:


Nuclear decommissioning ARO at December 31, 2020(a)	$	11,922
Accretion expense	249

Costs incurred related to decommissioning plants	(39)
Nuclear decommissioning ARO at June 30, 2021(a)	$	12,132

_________

(a)Includes $84 million and $80 million as the current portion of the ARO at June 30, 2021 and December 31, 2020, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

On July 28, 2021 Generation submitted PSDAR filings for the Byron and Dresden nuclear units, selecting the SAFSTOR decommissioning approach that allows for up to 60 years in duration, with certain aspects of the specific approach unique to each unit. Based on the approaches selected, and assuming the Byron and Dresden units retire as previously announced in September 2021 and November 2021, respectively, Generation expects to record an incremental increase in the nuclear decommissioning ARO of $650 million to $850 million in the second half of 2021. As discussed further below, contractual offset for the Byron units has been suspended and $275 million to $375 million of this increase in the ARO would result in a pre-tax charge in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

NDT Funds

Exelon and Generation had NDT funds totaling $15,596 million and $14,599 million at June 30, 2021 and December 31, 2020, respectively. The NDT funds also include $196 million and $134 million for the current portion of the NDT funds at June 30, 2021 and December 31, 2020, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 18 — Supplemental Financial Information for additional information on activities of the NDT funds.

Accounting Implications of the Regulatory Agreements with ComEd and PECO

Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are recorded by Generation and the corresponding regulated utility as a component of the intercompany and regulatory balances on the balance sheet. For the purposes of making this determination, the decommissioning obligation referred to is different from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 8 — Nuclear Decommissioning

For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, the offset of decommissioning-related activities within the Consolidated Statements of Operations and Comprehensive Income results with Generation recognizing an intercompany payable to ComEd while ComEd records an intercompany receivable from Generation with a corresponding regulatory liability. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible and accounting for decommissioning-related activities at Generation for that unit would not be offset, and the impact to Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income could be material during such periods. During the second quarter of 2021, a pre-tax charge of $53 million was recorded in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being suspended. Generation believes that additional growth of the NDT funds for the Byron units will ultimately be sufficient to cover the future costs of decommissioning.

As of June 30, 2021, decommissioning-related activities for all of the former ComEd units, except for Byron (see discussion above) and Zion (see Note 10 – Asset Retirement Obligations of the Exelon 2020 Form 10-K), are currently offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

See Note 10 – Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information, including the former PECO units.

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 February 24, 2021 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, 2020 for all units except for Byron Units 1 and 2. Prior to shutdown, Generation will supplement its July 28, 2021 PSDAR filing with decommissioning cost information for Byron Units 1 and 2 and will evaluate the status of funding assurance based on this cost information and updated trust fund values. If required, Generation intends to provide additional funding assurance by the time of shutdown.

Generation will file its next decommissioning funding status report with the NRC by March 31, 2022. This report will reflect the status of decommissioning funding assurance as of December 31, 2021 for shutdown units.

9. 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

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Asset Impairments

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.

New England Asset Group

In the third quarter of 2020, in conjunction with the retirement announcement of Mystic Units 8 and 9, Generation, recorded a pre-tax impairment charge of $500 million for the New England asset group. See Note 12 - Asset Impairments of the Exelon 2020 Form 10-K for additional information. In the second quarter of 2021, an overall decline in the asset group's portfolio value suggested that the carrying value of the New England asset group may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the carrying value was not recoverable and that its fair value was less than its carrying value. As a result, a pre-tax impairment charge of $350 million was recorded in the second quarter of 2021 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Midwest Asset Group

Generation will continue to monitor the recoverability of the carrying value of the Midwest asset group as circumstances continue to evolve in Illinois. See Note 7 — Early Plant Retirements for additional information.

10. 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, 2021

	Exelon(a)	Generation(a)	ComEd(a)	PECO(a)	BGE(a)(b)	PHI(a)	Pepco(a)	DPL(a)	ACE(a)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	1.4	(1.3)	8.0	(2.9)	(12.5)	2.4	(2.1)	7.0	8.1
Qualified NDT fund income	17.9	85.2	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	—	(1.8)	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(3.1)	—	(0.7)	(12.5)	(2.3)	(1.1)	(1.5)	(0.7)	(0.6)
Production tax credits and other credits	(1.9)	(13.0)	(0.8)	—	(3.6)	(0.8)	(0.7)	(0.9)	(0.6)
Noncontrolling interests	(0.9)	(4.2)	—	—	—	—	—	—	—
Excess deferred tax amortization	(10.4)	—	(7.0)	(3.3)	(17.5)	(22.3)	(19.0)	(21.9)	(28.2)

Other	(10.6)	2.8	(1.1)	(0.4)	(6.6)	(1.3)	(1.9)	(1.1)	(2.3)
Effective income tax rate	13.4%	88.7%	19.3%	1.9%	(21.6)%	(2.2)%	(4.2)%	3.2%	(2.8)%

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Income Taxes


	Three Months Ended June 30, 2020
	Exelon(a)	Generation(a)	ComEd(c)	PECO(d)	BGE(d)	PHI(d)	Pepco(d)	DPL(e)	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	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(f)	(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)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

(b)For BGE, the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits.

(c)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.

(d)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.

(e)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.

(f)For Exelon, "Other" is primarily driven by the reversal of the consolidating income tax adjustment recorded at Exelon Corporate in the first quarter of 2021 that was required pursuant to GAAP interim reporting guidance.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Income Taxes


	Six Months Ended June 30, 2021
	Exelon(a)	Generation(b)	ComEd(a)	PECO(a)(d)	BGE(a)(c)	PHI(a)	Pepco(a)	DPL(a)	ACE(a)
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	(12.6)	5.3	7.4	(2.1)	(10.5)	4.2	1.5	6.6	7.8
Qualified NDT fund income	56.2	(18.3)	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(2.5)	0.7	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(15.7)	—	(0.6)	(11.3)	(1.6)	(1.3)	(1.8)	(0.7)	(0.7)
Production tax credits and other credits	(11.0)	2.9	(0.5)	—	(0.9)	(0.5)	(0.5)	(0.4)	(0.5)
Noncontrolling interests	(2.5)	0.8	—	—	—	—	—	—	—
Excess deferred tax amortization	(50.9)	—	(7.0)	(3.3)	(15.9)	(20.8)	(17.2)	(19.7)	(28.3)

Other(e)	38.5	(3.9)	(2.3)	(0.1)	(1.0)	(0.7)	(0.8)	(0.1)	(1.1)
Effective income tax rate	20.5%	8.5%	17.9%	4.2%	(9.0)%	1.8%	2.2%	6.5%	(2.0)%


	Six Months Ended June 30, 2020
	Exelon(a)	Generation(a)	ComEd(a)(g)	PECO(a)(d)	BGE(a)(h)	PHI(a)(h)	Pepco(a)(h)	DPL(a)(h)	ACE(i)
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(f)	(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)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

(b)Generation recognized a loss before income taxes for the six months ended June 30, 2021. As a result, positive percentages represent an income tax benefit for the period presented.

(c)For BGE, the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits.

(d)For PECO, the lower effective tax rate is primarily attributable to plant basis differences attributable to tax repairs.

(e)For Exelon, "Other" is primarily driven by the consolidating income tax adjustment recorded at Exelon Corporate in the first quarter of 2021 that was required pursuant to GAAP interim reporting guidance. This incremental expense will reverse by year-end and will not have an impact on annual results.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Income Taxes

(f)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.

(g)At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments.

(h)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.

(i)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.

Unrecognized Tax Benefits

PHI and ACE have the following unrecognized tax benefits as of June 30, 2021 and December 31, 2020. Exelon's, Generation's, ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.


	PHI		ACE
June 30, 2021	$	54	$	16
December 31, 2020	52		15

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

As of June 30, 2021, ACE has approximately $14 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

11. Retirement Benefits (All Registrants)

Defined Benefit Pension and OPEB

During the first quarter of 2021, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2021. This valuation resulted in an increase to the pension obligations of $33 million and a decrease to the OPEB obligations of $9 million. Additionally, accumulated other comprehensive loss increased by $1 million (after-tax) and regulatory assets and liabilities increased by $21 million and $1 million, respectively.

The majority of the 2021 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 2.58%. The majority of the 2021 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.46% for funded plans and a discount rate of 2.51%.

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, 2021 and 2020.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Retirement Benefits



	Pension Benefits				OPEB
	Three Months Ended June 30,				Three Months Ended June 30,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	111	$	96	$	20	$	22
Interest cost	160		190		28		39
Expected return on assets	(333)		(318)		(39)		(40)
Amortization of:
Prior service cost (credit)	—		1		(9)		(31)
Actuarial loss	149		128		10		12
Settlement charges	4		6		—		—

Net periodic benefit cost	$	91	$	103	$	10	$	2



	Pension Benefits				OPEB
	Six Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	220	$	193	$	40	$	45
Interest cost	320		379		57		77
Expected return on assets	(667)		(636)		(79)		(81)
Amortization of:
Prior service cost (credit)	1		2		(17)		(62)
Actuarial loss	299		256		19		24
Curtailment benefits	—		—		(1)		—
Settlement charges	4		6		—		—

Net periodic benefit cost	$	177	$	200	$	19	$	3

The amounts below represent the Registrants' allocated pension and OPEB 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	2021		2020		2021		2020
Exelon	$	101	$	105	$	196	$	203
Generation	30		32		56		59
ComEd	32		28		64		57
PECO	2		1		4		3
BGE	16		16		31		31
PHI	12		18		24		35
Pepco	2		4		3		7
DPL	1		2		1		4
ACE	3		3		5		7

Defined Contribution Savings Plans

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Retirement Benefits

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 for the three and six months ended June 30, 2021 and 2020, respectively.


	Three Months Ended June 30,				Six Months Ended June 30,
Savings Plans Matching Contributions	2021		2020		2021		2020
Exelon	$	36	$	34	$	69	$	67
Generation	13		14		26		27
ComEd	10		9		18		16
PECO	3		2		6		5
BGE	2		2		4		4
PHI	4		3		7		6
Pepco	1		1		2		2
DPL	1		—		2		1
ACE	1		1		1		1

12. 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 derivatives settle 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 referenced 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, which 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

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

Note 12 — Derivative Financial Instruments

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

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

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

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

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

Note 12 — Derivative Financial Instruments

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	Electricity	NPNS	Fixed price contracts for default supply requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts to cover about 10% 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(b)	Exchange traded future contracts for up to 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 2020 Form 10-K for additional information.

(b)The fair value of the DPL economic hedge is not material as of June 30, 2021 and December 31, 2020 and is not presented in the fair value tables below.

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of June 30, 2021 and December 31, 2020:


	Exelon		Generation										ComEd
June 30, 2021	Total Derivatives		Economic Hedges		Proprietary Trading		Collateral(a)(b)		Netting(a)		Subtotal		Economic Hedges
Mark-to-market derivative assets (current assets)	$	748	$	6,541	$	64	$	(241)	$	(5,616)	$	748	$	—
Mark-to-market derivative assets (noncurrent assets)	438		1,997		10		(92)		(1,477)		438		—
Total mark-to-market derivative assets	1,186		8,538		74		(333)		(7,093)		1,186		—
Mark-to-market derivative liabilities (current liabilities)	(713)		(6,075)		(54)		(177)		5,616		(690)		(23)
Mark-to-market derivative liabilities (noncurrent liabilities)	(553)		(1,739)		(7)		(42)		1,477		(311)		(242)
Total mark-to-market derivative liabilities	(1,266)		(7,814)		(61)		(219)		7,093		(1,001)		(265)
Total mark-to-market derivative net assets (liabilities)	$	(80)	$	724	$	13	$	(552)	$	—	$	185	$	(265)

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

Note 12 — Derivative Financial Instruments


	Exelon		Generation										ComEd
December 31, 2020	Total Derivatives		Economic Hedges		Proprietary Trading		Collateral(a)(b)		Netting(a)		Subtotal		Economic Hedges
Mark-to-market derivative assets (current assets)	$	639	$	2,757	$	40	$	103	$	(2,261)	$	639	$	—
Mark-to-market derivative assets (noncurrent assets)	554		1,501		4		64		(1,015)		554		—
Total mark-to-market derivative assets	1,193		4,258		44		167		(3,276)		1,193		—
Mark-to-market derivative liabilities (current liabilities)	(293)		(2,629)		(23)		131		2,261		(260)		(33)
Mark-to-market derivative liabilities (noncurrent liabilities)	(472)		(1,335)		(2)		118		1,015		(204)		(268)
Total mark-to-market derivative liabilities	(765)		(3,964)		(25)		249		3,276		(464)		(301)
Total mark-to-market derivative net assets (liabilities)	$	428	$	294	$	19	$	416	$	—	$	729	$	(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)Includes $858 million held and $209 million posted of variation margin with the exchanges as of June 30, 2021 and December 31, 2020 respectively.

Economic Hedges (Commodity Price Risk)

Generation. For the three and six months ended June 30, 2021 and 2020, 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,
	2021		2020		2021		2020
Income Statement Location	Gain (Loss)				Gain (Loss)
Operating revenues	$	(240)	$	24	$	(323)	$	199
Purchased power and fuel	552		63		817		15
Total Exelon and Generation	$	312	$	87	$	494	$	214

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, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 98%-101% for 2021.

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, 2021 and 2020, net pre-tax commodity mark-to-market gains and losses for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.

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

Note 12 — Derivative Financial Instruments

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Generation utilizes interest rate swaps to manage its interest rate exposure and foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $629 million and $665 million for Exelon and Generation as of June 30, 2021 and December 31, 2020, respectively.

The mark-to-market derivative assets and liabilities as of June 30, 2021 and December 31, 2020 and the mark-to-market gains and losses for the three and six months ended June 30, 2021 and 2020 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 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.

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

Note 12 — Derivative Financial Instruments

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, 2021. 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 amounts 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, 2021	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	$	446	$	56	$	390	—	$	—
Non-investment grade	15		1		14
No external ratings
Internally rated — investment grade	134		1		133
Internally rated — non-investment grade	126		35		91
Total	$	721	$	93	$	628	—	$	—


Net Credit Exposure by Type of Counterparty	As of June 30, 2021
Financial institutions	$	27
Investor-owned utilities, marketers, power producers	448
Energy cooperatives and municipalities	85
Other	68
Total	$	628

_________

(a)As of June 30, 2021, credit collateral held from counterparties where Generation had credit exposure included $53 million of cash and $40 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, 2021, 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 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.

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

Note 12 — Derivative Financial Instruments

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, 2021		December 31, 2020
Gross fair value of derivative contracts containing this feature(a)	$	(2,173)	$	(834)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)	1,151		537
Net fair value of derivative contracts containing this feature(c)	$	(1,022)	$	(297)

_________

(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 Generation 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, 2021 and December 31, 2020, 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, 2021		December 31, 2020
Cash collateral posted	$	67	$	511
Letters of credit posted	344		226
Cash collateral held	621		110
Letters of credit held	50		40
Additional collateral required in the event of a credit downgrade below investment grade	1,899		1,432

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's, and DPL’s credit rating. As of June 30, 2021, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of June 30, 2021, they could have been required to post incremental collateral to their counterparties of $22 million, $40 million and $12 million, respectively.

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

Note 13 — Debt and Credit Agreements

13. 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, 2021 and December 31, 2020. PECO and BGE had no commercial paper borrowings as of both June 30, 2021 and December 31, 2020.


	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	June 30, 2021		December 31, 2020		June 30, 2021		December 31, 2020
Exelon(a)	$	365	$	1,031	0.17	%	0.25	%
Generation	—		340		—	%	0.27	%
ComEd	33		323		0.15	%	0.23	%


PHI(b)	332		368		0.17	%	0.24	%

Pepco	154		35		0.17	%	0.22	%
DPL	—		146		—	%	0.24	%
ACE	178		187		0.18	%	0.25	%

__________

(a)Exelon Corporate had no outstanding commercial paper borrowings as of both June 30, 2021 and December 31, 2020.

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

See Note 17 – Debt and Credit Agreements of the Exelon 2020 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 17, 2021 and will expire on March 16, 2022. 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 Sheets within Short-term borrowings.

On March 24, 2021, Exelon Corporate entered into a 9-month term loan agreement for $200 million. The loan agreement has an expiration of December 24, 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 Sheets within Short-term borrowings.

On March 31, 2021, Exelon Corporate entered into a 9-month and 364-day term loan agreement for $150 million each with variable interest rates of LIBOR plus 0.65% and expiration dates of December 31, 2021 and March 30, 2022, respectively. The loan agreements are reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.

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

Note 13 — Debt and Credit Agreements

On March 19, 2020, Generation entered into a term loan agreement for $200 million. The loan agreement was renewed on March 17, 2021 and will expire on March 16, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.875% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's and Generation's Consolidated Balance Sheets within Short-term borrowings.

On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement was renewed on March 30, 2021 and will expire on March 29, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.70% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's and Generation's Consolidated Balance Sheets within Short-term borrowings.

On January 25, 2021, ComEd entered into two 90-day term loan agreements for $125 million each with variable interest rates of LIBOR plus 0.50% and LIBOR plus 0.75%, respectively. ComEd repaid the term loans on March 9, 2021.

Bilateral Credit Agreements

On January 11, 2013, Generation entered into a bilateral credit agreement for $100 million. The agreement was renewed on March 1, 2021 with a maturity date of March 1, 2023.

On February 21, 2019, Generation entered into a bilateral credit agreement for $100 million. The agreement was renewed on March 31, 2021 with a maturity date of March 31, 2022.

On January 5, 2016, Generation entered into a bilateral credit agreement for $150 million. The agreement was renewed on April 2, 2021 with a maturity date of April 5, 2023.

See Note 17 – Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on Generation's bilateral credit agreements.

Credit Agreements

On July 15, 2021, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2024.

Long-Term Debt

Issuance of Long-Term Debt

During the six months ended June 30, 2021, the following long-term debt was issued:

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

Note 13 — Debt and Credit Agreements

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Long-Term Software License Agreements

3.62

December 1, 2025

Procurement of software licenses.

Generation

West Medway II
Nonrecourse Debt

LIBOR + 3%

(a)

March 31, 2026

150

Funding for general corporate purposes.

Generation

Energy Efficiency Project Financing(b)

2.53

August 31, 2021

Funding to install energy conservation measures for the Fort AP Hill project.

ComEd

First Mortgage Bonds, Series 130

3.13

March 15, 2051

700

Repay a portion of outstanding commercial paper obligations and two outstanding term loans, and to fund other general corporate purposes.

PECO

First and Refunding Mortgage Bonds

3.05

March 15, 2051

375

Funding for general corporate purposes.

BGE

Senior Notes

2.25

June 15, 2031

600

Repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes.

Pepco(c)

First Mortgage Bonds

2.32

March 30, 2031

150

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

3.24

March 30, 2051

125

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

2.30

March 15, 2031

350

Refinance existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.

__________

(a)The nonrecourse debt has an average blended interest rate.

(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 March 30, 2021, Pepco entered into a purchase agreement of First Mortgage Bonds of $125 million at 3.29% due on September 28, 2051. The closing date of the issuance is expected to occur in September 2021.

Debt Covenants

As of June 30, 2021, 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.

West Medway II, LLC. On May 13, 2021, West Medway II, LLC (West Medway II), an indirect subsidiary of Generation, entered into a financing agreement for a $150 million nonrecourse senior secured term loan credit facility with a maturity date of March 31, 2026. The term loan bears interest at an average blended interest rate of LIBOR plus 3%, paid quarterly. In addition to the financing, West Medway II, entered into interest rate swaps with an initial notional amount of $113 million at an interest rate of 0.61%, paid quarterly, to manage a portion of the interest rate exposure in connection with financing. The net proceeds were distributed to Generation for general

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

Note 13 — Debt and Credit Agreements

corporate purposes. Generation’s interests in West Medway II, were pledged as collateral for this financing. As of June 30, 2021 approximately $150 million was outstanding.

See Note 17 – Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on nonrecourse debt and Note 12 – Derivative Financial Instruments for additional information on interest rate swaps.

14. 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.

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, 2021 and December 31, 2020. 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, 2021								December 31, 2020
	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	$	38,710	$	40,956	$	3,189	$	44,145	$	36,912	$	40,688	$	3,064	$	43,752
Generation	6,178		5,776		1,145		6,921		6,087		5,648		1,208		6,856
ComEd	9,675		11,407		—		11,407		8,983		11,117		—		11,117
PECO	4,125		4,722		50		4,772		3,753		4,553		50		4,603
BGE	4,259		4,748		—		4,748		3,664		4,366		—		4,366
PHI	7,369		6,048		1,994		8,042		7,006		6,099		1,806		7,905
Pepco	3,318		3,240		860		4,100		3,165		3,336		748		4,084
DPL	1,804		1,434		556		1,990		1,677		1,484		455		1,939
ACE	1,515		1,117		578		1,695		1,413		1,018		602		1,620
Long-Term Debt to Financing Trusts(a)
Exelon	$	390	$	—	$	482	$	482	$	390	$	—	$	467	$	467
ComEd	205		—		253		253		205		—		246		246
PECO	184		—		229		229		184		—		221		221
SNF Obligation
Exelon	$	1,209	$	995	$	—	$	995	$	1,208	$	909	$	—	$	909
Generation	1,209		995		—		995		1,208		909		—		909

__________

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

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

Note 14 — 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, 2021 and December 31, 2020:

Exelon and Generation


	Exelon										Generation
As of June 30, 2021	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)	$	1,167	$	—	$	—	$	—	$	1,167	$	162	$	—	$	—	$	—	$	162
NDT fund investments
Cash equivalents(b)	552		75		—		—		627		552		75		—		—		627



Equities	4,770		1,720		—		1,671		8,161		4,770		1,720		—		1,671		8,161
Fixed income
Corporate debt(c)	—		1,146		285		—		1,431		—		1,146		285		—		1,431
U.S. Treasury and agencies	2,052		39		—		—		2,091		2,052		39		—		—		2,091
Foreign governments	—		51		—		—		51		—		51		—		—		51
State and municipal debt	—		28		—		—		28		—		28		—		—		28
Other	32		31		—		1,113		1,176		32		31		—		1,113		1,176
Fixed income subtotal	2,084		1,295		285		1,113		4,777		2,084		1,295		285		1,113		4,777
Private credit	—		—		176		607		783		—		—		176		607		783
Private equity	—		—		—		580		580		—		—		—		580		580
Real estate	—		—		—		762		762		—		—		—		762		762

NDT fund investments subtotal(d)(e)	7,406		3,090		461		4,733		15,690		7,406		3,090		461		4,733		15,690
Rabbi trust investments
Cash equivalents	65		—		—		—		65		4		—		—		—		4
Mutual funds	99		—		—		—		99		33		—		—		—		33
Fixed income	—		11		—		—		11		—		—		—		—		—
Life insurance contracts	—		94		34		—		128		—		31		—		—		31
Rabbi trust investments subtotal	164		105		34		—		303		37		31		—		—		68
Investments in equities(f)	327		—		—		—		327		327		—		—		—		327
Commodity derivative assets
Economic hedges	1,781		3,917		2,840		—		8,538		1,781		3,917		2,840		—		8,538
Proprietary trading	—		62		12		—		74		—		62		12		—		74
Effect of netting and allocation of collateral(g)(h)	(1,411)		(3,502)		(2,513)		—		(7,426)		(1,411)		(3,502)		(2,513)		—		(7,426)
Commodity derivative assets subtotal	370		477		339		—		1,186		370		477		339		—		1,186
DPP consideration	—		374		—		—		374		—		374		—		—		374

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

Note 14 — Fair Value of Financial Assets and Liabilities


	Exelon										Generation
As of June 30, 2021	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Total assets	9,434		4,046		834		4,733		19,047		8,302		3,972		800		4,733		17,807
Liabilities
Commodity derivative liabilities
Economic hedges	(1,245)		(3,444)		(3,390)		—		(8,079)		(1,245)		(3,444)		(3,125)		—		(7,814)
Proprietary trading	—		(45)		(16)		—		(61)		—		(45)		(16)		—		(61)
Effect of netting and allocation of collateral(g)(h)	1,242		3,295		2,337		—		6,874		1,242		3,295		2,337		—		6,874
Commodity derivative liabilities subtotal	(3)		(194)		(1,069)		—		(1,266)		(3)		(194)		(804)		—		(1,001)
Deferred compensation obligation	—		(144)		—		—		(144)		—		(42)		—		—		(42)
Total liabilities	(3)		(338)		(1,069)		—		(1,410)		(3)		(236)		(804)		—		(1,043)
Total net assets (liabilities)	$	9,431	$	3,708	$	(235)	$	4,733	$	17,637	$	8,299	$	3,736	$	(4)	$	4,733	$	16,764


	Exelon										Generation
As of December 31, 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)	$	686	$	—	$	—	$	—	$	686	$	124	$	—	$	—	$	—	$	124
NDT fund investments
Cash equivalents(b)	210		95		—		—		305		210		95		—		—		305



Equities	3,886		2,077		—		1,562		7,525		3,886		2,077		—		1,562		7,525
Fixed income
Corporate debt(c)	—		1,485		285		—		1,770		—		1,485		285		—		1,770
U.S. Treasury and agencies	1,871		126		—		—		1,997		1,871		126		—		—		1,997
Foreign governments	—		56		—		—		56		—		56		—		—		56
State and municipal debt	—		101		—		—		101		—		101		—		—		101
Other	—		41		—		961		1,002		—		41		—		961		1,002
Fixed income subtotal	1,871		1,809		285		961		4,926		1,871		1,809		285		961		4,926
Private credit	—		—		212		629		841		—		—		212		629		841
Private equity	—		—		—		504		504		—		—		—		504		504
Real estate	—		—		—		679		679		—		—		—		679		679

NDT fund investments subtotal(d)(e)	5,967		3,981		497		4,335		14,780		5,967		3,981		497		4,335		14,780
Rabbi trust investments
Cash equivalents	60		—		—		—		60		4		—		—		—		4
Mutual funds	91		—		—		—		91		29		—		—		—		29
Fixed income	—		11		—		—		11		—		—		—		—		—
Life insurance contracts	—		87		34		—		121		—		28		—		—		28
Rabbi trust investments subtotal	151		98		34		—		283		33		28		—		—		61
Investments in equities(f)	195		—		—		—		195		195		—		—		—		195
Commodity derivative assets
Economic hedges	745		1,914		1,599		—		4,258		745		1,914		1,599		—		4,258
Proprietary trading	—		17		27		—		44		—		17		27		—		44

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Fair Value of Financial Assets and Liabilities


	Exelon										Generation
As of December 31, 2020	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Effect of netting and allocation of collateral(g)(h)	(607)		(1,597)		(905)		—		(3,109)		(607)		(1,597)		(905)		—		(3,109)
Commodity derivative assets subtotal	138		334		721		—		1,193		138		334		721		—		1,193
DPP consideration	—		639		—		—		639		—		639		—		—		639
Total assets	7,137		5,052		1,252		4,335		17,776		6,457		4,982		1,218		4,335		16,992
Liabilities
Commodity derivative liabilities
Economic hedges	(682)		(1,928)		(1,655)		—		(4,265)		(682)		(1,928)		(1,354)		—		(3,964)
Proprietary trading	—		(21)		(4)		—		(25)		—		(21)		(4)		—		(25)
Effect of netting and allocation of collateral(g)(h)	540		1,918		1,067		—		3,525		540		1,918		1,067		—		3,525
Commodity derivative liabilities subtotal	(142)		(31)		(592)		—		(765)		(142)		(31)		(291)		—		(464)
Deferred compensation obligation	—		(145)		—		—		(145)		—		(42)		—		—		(42)
Total liabilities	(142)		(176)		(592)		—		(910)		(142)		(73)		(291)		—		(506)
Total net assets	$	6,995	$	4,876	$	660	$	4,335	$	16,866	$	6,315	$	4,909	$	927	$	4,335	$	16,486

__________

(a)Exelon excludes cash of $728 million and $409 million at June 30, 2021 and December 31, 2020, respectively, and restricted cash of $114 million and $59 million at June 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $52 million and $53 million at June 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $407 million and $171 million at June 30, 2021 and December 31, 2020, respectively, and restricted cash of $32 million and $20 million at June 30, 2021 and December 31, 2020, respectively.

(b)Includes $103 million and $116 million of cash received from outstanding repurchase agreements at June 30, 2021 and December 31, 2020, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (e) below.

(c)Includes investments in equities sold short of $(52) million and $(62) million as of June 30, 2021 and December 31, 2020, respectively, held in an investment vehicle primarily to hedge the equity option component of its convertible debt.

(d)Includes derivative assets of less than $1 million and $2 million, which have total notional amounts of $2,016 million and $1,043 million at June 30, 2021 and December 31, 2020, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of Exelon and Generation's exposure to credit or market loss.

(e)Excludes net liabilities of $94 million and $181 million at June 30, 2021 and December 31, 2020, respectively, which include certain derivative assets that have notional amounts of $137 million and $104 million at June 30, 2021 and December 31, 2020, 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.

(f)Includes equity investments held by Generation which were previously designated as equity investments without readily determinable fair value but are now publicly traded and therefore have readily determinable fair values. The first investment became publicly traded in the fourth quarter of 2020. Generation recorded the fair value of these investments in Other current assets on Exelon's and Generation's Consolidated Balance Sheets based on the quoted market prices of the stocks at June 30, 2021, which resulted in unrealized gains for investments that became publicly traded during 2021 of $102 million and $220 million within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the three and six months ended June 30, 2021, respectively.

(g)Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $(169) million, $(207) million, and $(176) million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of June 30, 2021. Collateral (received)/posted from counterparties, net of collateral paid to counterparties, totaled $(67) million, $321 million, and $162 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2020.

(h)Includes $858 million held and $209 million posted of variation margin with the exchanges as of June 30, 2021 and December 31, 2020, respectively.

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

Note 14 — Fair Value of Financial Assets and Liabilities

As of June 30, 2021, Exelon and Generation have outstanding commitments to invest in private credit, private equity, and real estate investments of approximately $364 million, $224 million, and $320 million, respectively. These commitments will be funded by Generation’s existing NDT funds.

Exelon and Generation held investments without readily determinable fair values with carrying amounts of $38 million and $26 million as of June 30, 2021, respectively. Exelon and Generation held investments without readily determinable fair values with carrying amounts of $73 million and $55 million as of December 31, 2020, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three and six months ended June 30, 2021 and for the year ended December 31, 2020.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Fair Value of Financial Assets and Liabilities

ComEd, PECO, and BGE


	ComEd								PECO								BGE
As of June 30, 2021	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	264	$	—	$	—	$	264	$	230	$	—	$	—	$	230	$	334	$	—	$	—	$	334
Rabbi trust investments

Mutual funds	—		—		—		—		10		—		—		10		14		—		—		14
Life insurance contracts	—		—		—		—		—		15		—		15		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		10		15		—		25		14		—		—		14
Total assets	264		—		—		264		240		15		—		255		348		—		—		348
Liabilities
Deferred compensation obligation	—		(9)		—		(9)		—		(8)		—		(8)		—		(6)		—		(6)
Mark-to-market derivative liabilities(b)	—		—		(265)		(265)		—		—		—		—		—		—		—		—
Total liabilities	—		(9)		(265)		(274)		—		(8)		—		(8)		—		(6)		—		(6)
Total net assets (liabilities)	$	264	$	(9)	$	(265)	$	(10)	$	240	$	7	$	—	$	247	$	348	$	(6)	$	—	$	342


	ComEd								PECO								BGE
As of December 31, 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)	$	285	$	—	$	—	$	285	$	8	$	—	$	—	$	8	$	120	$	—	$	—	$	120
Rabbi trust investments
Mutual funds	—		—		—		—		9		—		—		9		10		—		—		10
Life insurance contracts	—		—		—		—		—		13		—		13		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		9		13		—		22		10		—		—		10
Total assets	285		—		—		285		17		13		—		30		130		—		—		130
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)	$	285	$	(8)	$	(301)	$	(24)	$	17	$	4	$	—	$	21	$	130	$	(5)	$	—	$	125

__________

(a)ComEd excludes cash of $44 million and $83 million at June 30, 2021 and December 31, 2020, respectively, and restricted cash of $46 million and $37 million at June 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $43 million at both June 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $154 million and $18 million at June 30, 2021 and December 31, 2020, respectively. BGE excludes cash of $34 million and $24 million at June 30, 2021 and December 31, 2020, respectively, and restricted cash of $3 million and $1 million at June 30, 2021 and December 31, 2020, respectively.

(b)The Level 3 balance consists of the current and noncurrent liability of $23 million and $242 million, respectively, at June 30, 2021 and $33 million and $268 million, respectively, at December 31, 2020 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL, and ACE



	As of June 30, 2021								As of December 31, 2020
PHI	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	46	$	—	$	—	$	46	$	86	$	—	$	—	$	86




Rabbi trust investments
Cash equivalents	59		—		—		59		55		—		—		55
Mutual funds	14		—		—		14		14		—		—		14
Fixed income	—		11		—		11		—		11		—		11
Life insurance contracts	—		26		34		60		—		26		34		60
Rabbi trust investments subtotal	73		37		34		144		69		37		34		140
Total assets	119		37		34		190		155		37		34		226
Liabilities
Deferred compensation obligation	—		(16)		—		(16)		—		(17)		—		(17)



Total liabilities	—		(16)		—		(16)		—		(17)		—		(17)
Total net assets	$	119	$	21	$	34	$	174	$	155	$	20	$	34	$	209


	Pepco								DPL								ACE
As of June 30, 2021	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)	$	28	$	—	$	—	$	28	$	5	$	—	$	—	$	5	$	12	$	—	$	—	$	12




Rabbi trust investments
Cash equivalents	57		—		—		57		—		—		—		—		—		—		—		—
Fixed income	—		2		—		2		—		—		—		—		—		—		—		—
Life insurance contracts	—		26		34		60		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	57		28		34		119		—		—		—		—		—		—		—		—
Total assets	85		28		34		147		5		—		—		5		12		—		—		12
Liabilities
Deferred compensation obligation	—		(2)		—		(2)		—		—		—		—		—		—		—		—



Total liabilities	—		(2)		—		(2)		—		—		—		—		—		—		—		—
Total net assets	$	85	$	26	$	34	$	145	$	5	$	—	$	—	$	5	$	12	$	—	$	—	$	12

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Fair Value of Financial Assets and Liabilities


	Pepco								DPL								ACE
As of December 31, 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)	$	35	$	—	$	—	$	35	$	—	$	—	$	—	$	—	$	13	$	—	$	—	$	13




Rabbi trust investments
Cash equivalents	53		—		—		53		—		—		—		—		—		—		—		—

Fixed income	—		2		—		2		—		—		—		—		—		—		—		—
Life insurance contracts	—		26		34		60		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	53		28		34		115		—		—		—		—		—		—		—		—
Total assets	88		28		34		150		—		—		—		—		13		—		—		13
Liabilities
Deferred compensation obligation	—		(2)		—		(2)		—		—		—		—		—		—		—		—



Total liabilities	—		(2)		—		(2)		—		—		—		—		—		—		—		—
Total net assets	$	88	$	26	$	34	$	148	$	—	$	—	$	—	$	—	$	13	$	—	$	—	$	13

__________

(a)PHI excludes cash of $61 million and $74 million at June 30, 2021 and December 31, 2020, respectively, and restricted cash of $5 million and none at June 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $9 million and $10 million at June 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $17 million and $30 million at June 30, 2021 and December 31, 2020, respectively, and restricted cash of $5 million and none at June 30, 2021 and December 31, 2020, respectively. DPL excludes cash of $17 million and $15 million at June 30, 2021 and December 31, 2020, respectively. ACE excludes cash of $11 million and $17 million at June 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $9 million and $10 million at June 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.

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, 2021 and 2020:



	Exelon		Generation					ComEd		PHI and Pepco
Three Months Ended June 30, 2021	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, 2021	$	426	$	479	$	207		$	686	$	(295)		$	35	$	—
Total realized / unrealized gains (losses)
Included in net income	(357)		1		(359)		(a)	(358)		—			1		—
Included in noncurrent payables to affiliates	—		6		—			6		—			—		(6)

Included in regulatory assets	36		—		—			—		30		(b)	—		6
Change in collateral	(282)		—		(282)			(282)		—			—		—
Purchases, sales, and settlements
Purchases	7		1		6			7		—			—		—
Sales	1		—		1			1		—			—		—

Settlements	(28)		(26)		—			(26)		—			(2)		—
Transfers into Level 3	1		—		1		(c)	1		—			—		—
Transfers out of Level 3	(39)		—		(39)		(c)	(39)		—			—		—
Balance at June 30, 2021	$	(235)	$	461	$	(465)		$	(4)	$	(265)		$	34	$	—
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, 2021	$	(372)	$	1	$	(374)		$	(373)	$	—		$	1	$	—

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

Note 14 — Fair Value of Financial Assets and Liabilities


	Exelon		Generation					ComEd		PHI and Pepco
Six months ended June 30, 2021	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, 2020	$	660	$	497	$	430		$	927	$	(301)		$	34	$	—
Total realized / unrealized gains (losses)
Included in net income	(632)		2		(636)		(a)	(634)		—			2		—
Included in noncurrent payables to affiliates	—		7		—			7		—			—		(7)

Included in regulatory assets	43		—		—			—		36		(b)	—		7
Change in collateral	(338)		—		(338)			(338)		—			—		—
Purchases, sales, and settlements
Purchases	115		1		114			115		—			—		—
Sales	1		—		1			1		—			—		—

Settlements	(48)		(46)		—			(46)		—			(2)		—
Transfers into Level 3	1		—		1		(c)	1		—			—		—
Transfers out of Level 3	(37)		—		(37)		(c)	(37)		—			—		—
Balance as of June 30, 2021	$	(235)	$	461	$	(465)		$	(4)	$	(265)		$	34	$	—
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, 2021	$	(518)	$	2	$	(522)		$	(520)	$	—		$	2	$	—



	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, 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 as of 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	$	—

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Fair Value of Financial Assets and Liabilities


	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, 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	$	—

__________

(a)Includes an addition of $15 million for realized losses and a reduction of $114 million for realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2021. Includes a reduction of $94 million and $271 million for realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2020.

(b)Includes $25 million of increases in fair value and an increase for realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2021. Includes $23 million of increases 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, 2021. 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 decrease 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.

(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, 2021 and 2020:




	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 (losses) gains included in net income for the three months ended June 30, 2021	$	(555)	$	196	$	1	$	1	$	(555)	$	196	$	1	$	1
Total (losses) gain included in net income for the six months ended June 30, 2021	(670)		34		2		2		(670)		34		2		2
Total unrealized (losses) gains for the three months ended June 30, 2021	(543)		169		1		1		(543)		169		1		1
Total unrealized (losses) gains for the six months ended June 30, 2021	(608)		86		2		2		(608)		86		2		2

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

Note 14 — Fair Value of Financial Assets and Liabilities



	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 (losses) gains included in net income for the three months ended June 30, 2020	$	(137)	$	(29)	$	1	$	—	$	(137)	$	(29)	$	—	$	1
Total (losses) gains included in net income 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

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 18 — Fair Value of Financial Assets and Liabilities of the Exelon 2020 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.

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Note 14 — 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, 2021		Fair Value at December 31, 2020		Valuation Technique	Unobservable Input	2021 Range & Arithmetic Average				2020 Range & Arithmetic Average
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)	$	(285)	$	245	Discounted Cash Flow	Forward power price	$7.13	-	$281	$39	$2.25	-	$163	$30
						Forward gas price	$1.53	-	$12.51	$3.10	$1.57	-	$7.88	$2.59
					Option Model	Volatility percentage	11%	-	209%	33%	11%	-	237%	32%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)	$	(4)	$	23	Discounted Cash Flow	Forward power price	$10	-	$132	$38	$10	-	$106	$27

Mark-to-market derivatives (Exelon and ComEd)	$	(265)	$	(301)	Discounted Cash Flow	Forward heat rate(c)	9x	-	10x	9.13x	8x	-	9x	8.85x
						Marketability reserve	3%	-	7%	4.77%	3%	-	8%	4.93%
						Renewable factor	94%	-	122%	99%	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 (received)/posted on level three positions of $(176) million and $162 million as of June 30, 2021 and December 31, 2020, 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.

15. Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 19 of the Exelon 2020 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 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, 2021:

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Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments(a)	76		63		52		7		4

__________

(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 $135 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, 2021, approximately 33 MWs of new generation were developed and Exelon and Generation have incurred costs of $121 million. Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the DPSC in 2019. The third and final 40 MW wind REC tranche will be conducted in 2022.

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Commercial Commitments (All Registrants). The Registrants’ commercial commitments as of June 30, 2021, representing commitments potentially triggered by future events were as follows:


			Expiration within
	Total		2021		2022		2023		2024		2025		2026 and beyond
Exelon
Letters of credit	$	1,751	$	591	$	1,160	$	—	$	—	$	—	$	—
Surety bonds(a)	920		619		299		—		2		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values(b)	30		—		3		3		6		6		12
Total commercial commitments	$	3,079	$	1,210	$	1,462	$	3	$	8	$	6	$	390

Generation
Letters of credit	$	1,735	$	578	$	1,157	$	—	$	—	$	—	$	—
Surety bonds(a)	772		514		258		—		—		—		—
Total commercial commitments	$	2,507	$	1,092	$	1,415	$	—	$	—	$	—	$	—

ComEd
Letters of credit	$	7	$	7	$	—	$	—	$	—	$	—	$	—
Surety bonds(a)	17		9		6		—		2		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	224	$	16	$	6	$	—	$	2	$	—	$	200

PECO
Surety bonds(a)	$	3	$	1	$	2	$	—	$	—	$	—	$	—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	181	$	1	$	2	$	—	$	—	$	—	$	178

BGE
Letters of credit	$	2	$	—	$	2	$	—	$	—	$	—	$	—
Surety bonds(a)	3		2		1		—		—		—		—
Total commercial commitments	$	5	$	2	$	3	$	—	$	—	$	—	$	—

PHI

Surety bonds(a)	$	25	$	8	$	17	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	30		—		3		3		6		6		12
Total commercial commitments	$	55	$	8	$	20	$	3	$	6	$	6	$	12

Pepco

Surety bonds(a)	$	17	$	4	$	13	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	10		—		1		1		2		2		4
Total commercial commitments	$	27	$	4	$	14	$	1	$	2	$	2	$	4

DPL

Surety bonds(a)	$	4	$	2	$	2	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	13		—		1		1		3		3		5
Total commercial commitments	$	17	$	2	$	3	$	1	$	3	$	3	$	5

ACE
Surety bonds(a)	$	4	$	2	$	2	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	7		—		1		1		1		1		3
Total commercial commitments	$	11	$	2	$	3	$	1	$	1	$	1	$	3

__________

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

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(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 $75 million guaranteed by Exelon and PHI, of which $26 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 2026.

•PECO has 7 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 2023.

•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 2023.

•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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As of June 30, 2021 and December 31, 2020, 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, 2021				December 31, 2020
	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	$	461	$	297	$	483	$	314
Generation	117		—		121		—
ComEd	273		272		293		293
PECO	22		20		23		21
BGE	6		5		2		—
PHI	43		—		44		—
Pepco	41		—		42		—
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 Amendment (RODA) for the selection of a final remedy. The RODA modified the remedy previously selected by EPA in its 2008 Record of Decision (ROD). While the ROD required only that the radiological materials and other wastes at the site be capped, the 2018 RODA requires partial excavation of the radiological materials in addition to the previously selected capping remedy. The RODA 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 a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, 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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Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation and Feasibility Study (RI/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 $30 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 August 31, 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 has directed that the PRPs must submit a good faith joint proposed settlement offer. At this time, the DOJ has stayed their request for a good faith offer while the parties review cost documentation associated with the cost claim. 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 on February 3, 2020. Pepco and Generation are developing 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 March 16, 2022. After completion and approval of the FS, DOEE will prepare a Proposed Plan for public comment and then issue a ROD identifying any further response actions determined to be necessary. PHI, Pepco, and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.

Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and NPS 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. 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. On September 30, 2020, DOEE

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released its Interim ROD. The Interim ROD reflects an adaptive management approach which will require 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, but management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.

On July 12, 2021, DOEE and NPS held a virtual meeting with the PRP's in response to a General Notice Letter sent by each agency inviting the PRP's to participate in discussions, which PEPCO attended.

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. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a Natural Resources Damages (NRD) assessment, a 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, 2021 and December 31, 2020, Exelon and Generation had recorded estimated liabilities of approximately $85 million and $89 million, respectively, in total for asbestos-related bodily injury claims. As of June 30, 2021, approximately $21 million of this amount related to 230 open claims presented to Generation, while the remaining $64 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.

Deferred Prosecution Agreement (DPA) and Related Matters (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 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 U.S. Treasury of $200 million, which was paid in November 2020. Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended 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

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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.

Subsequent to Exelon announcing the receipt of the subpoenas, various lawsuits were filed, and various demand letters were received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:

•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. The court denied the motion in April 2021. On May 26, 2021, defendants moved the court to certify its order denying the motion to dismiss for interlocutory appeal. Briefing on the motion was completed in June 2021 and the motion remains pending. While that motion remains pending, the litigation has proceeded and in May 2021, the parties each filed respective initial discovery disclosures. On June 9, 2021, defendants filed their answer and affirmative defenses to the complaint. The parties are currently engaged in discovery.

•Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. The cases were consolidated into a single action in October of 2020. In November 2020, the Citizens Utility Board (CUB) filed a motion to intervene in the cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied CUB’s request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion was completed on March 2, 2021. The parties agreed, on March 25, 2021, along with the federal court plaintiffs, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. Oral argument on the state court motion to dismiss was held on August 4, 2021. No ruling has yet been issued.

•Four putative class action lawsuits against ComEd and Exelon were filed in federal court in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, CUB filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. In addition, on December 2, 2020, the court appointed interim lead plaintiffs in the federal cases which consisted of counsel for three of the four federal cases. These plaintiffs filed a consolidated complaint on January 5, 2021. CUB also filed its own complaint against ComEd only on the same day. The remaining federal case, Potter, et al. v. Exelon et al, differed from the other lawsuits as it named additional individual defendants not named in the consolidated complaint. The Potter plaintiffs decided not to move forward with their separate lawsuit at this time and voluntarily dismissed their complaint without prejudice on April 5, 2021. ComEd and Exelon moved to dismiss the consolidated class action complaint and CUB’s complaint on February 4, 2021. Briefing on that motion was completed on March 22, 2021. As noted above, on March 25, 2021, the parties agreed, along with the state court plaintiffs, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On June 14, 2021, plaintiffs filed a motion for leave to file a sur-reply to defendants' motion to dismiss, to which ComEd and Exelon objected. The court has taken the motion for leave under advisement.

•Five shareholders sent letters to the Exelon Board of Directors between 2020 and 2021 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (“SLC”) consisting of disinterested and independent parties to investigate and address these shareholders’ allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC’s investigation. In July, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter.

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

Note 15 — Commitments and Contingencies

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.

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages (Exelon and Generation). Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. See Note 3 — Regulatory Matters for additional information.

Various lawsuits have been filed against Generation since March 2021 related to these events, including:

•On March 5, 2021, Generation, along with more than 160 power generators and transmission and distribution companies, was sued by approximately 160 individually named plaintiffs, purportedly on behalf of all Texans who allegedly suffered loss of life or sustained personal injury, property damage or other losses as a result of the weather events. The plaintiffs allege that the defendants failed to properly prepare for the cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. On April 26, 2021, another multi-plaintiff lawsuit was filed on behalf of approximately 90 plaintiffs against more than 300 defendants, including Generation, involving similar allegations of liability and claims of personal injury and property damage. Since March 2021, approximately 60 additional lawsuits, naming multiple defendants including Generation, were filed by individual or multiple plaintiffs in different Texas counties, all arising out of the February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators. Generation disputes liability and denies that it is responsible for any of plaintiffs’ alleged claims and is vigorously contesting them. No loss contingencies have been reflected in Exelon’s and Generation’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.

•On March 22, 2021, a LDC filed a lawsuit in Missouri federal court against Generation for breach of contract and unjust enrichment, seeking damages of approximately $40 million. The plaintiff claims that Generation failed to deliver gas to its customers in February of 2021, causing the plaintiff to incur damages by forcing it to purchase gas for Generation’s customers and by Generation’s refusal to pay the resulting penalties. On March 26, 2021, Generation filed a complaint with the MPSC against the LDC to void the OFO penalties, or alternatively to grant a waiver or variance from the tariff requirements, to prohibit the LDC from billing or otherwise attempting to collect from Generation or any Missouri customer any portion of the penalties claimed by the LDC until the resolution of the complaint, and to prohibit the LDC from taking any retaliatory measure, including termination of service. The MPSC has scheduled an evidentiary hearing for January 2022. Based on the penalty provisions within the tariff that was in effect at the relevant time, Exelon and Generation have recorded a liability of approximately $40 million as of June 30, 2021.

General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

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

Note 16 — Changes in Accumulated Other Comprehensive Income

16. 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, 2021	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items (a)		Foreign Currency Items		Total
Beginning balance	$	(5)	$	(3,319)	$	(22)	$	(3,346)
OCI before reclassifications	—		—		2		2
Amounts reclassified from AOCI	—		55		—		55
Net current-period OCI	—		55		2		57
Ending balance	$	(5)	$	(3,264)	$	(20)	$	(3,289)


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)


Six Months Ended June 30, 2021	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items (a)		Foreign Currency Items		Total
Beginning balance	$	(5)	$	(3,372)	$	(23)	$	(3,400)
OCI before reclassifications	—		(2)		3		1
Amounts reclassified from AOCI	—		110		—		110
Net current-period OCI	—		108		3		111
Ending balance	$	(5)	$	(3,264)	$	(20)	$	(3,289)


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)

______

(a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 11 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

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

Note 16 — Changes in Accumulated Other Comprehensive Income

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,
	2021		2020		2021		2020
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	1	$	4	$	2	$	8
Actuarial loss reclassified to periodic benefit cost	(19)		(17)		(38)		(34)
Pension and non-pension postretirement benefit plans valuation adjustment	(1)		—		(1)		3

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

At June 30, 2021 and December 31, 2020, 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, 2021 and December 31, 2020. 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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(Dollars in millions, except per share data, unless otherwise noted)

Note 17 — Variable Interest Entities


	June 30, 2021								December 31, 2020
	Exelon		Generation		PHI (a)		ACE		Exelon		Generation		PHI (a)		ACE
Cash and cash equivalents	$	233	$	233	$	—	$	—	$	98	$	98	$	—	$	—
Restricted cash and cash equivalents	57		54		3		3		47		44		3		3
Accounts receivable
Customer	169		169		—		—		148		148		—		—
Other	44		44		—		—		36		36		—		—
Unamortized energy contract assets	22		22		—		—		22		22		—		—
Inventories, net

Materials and supplies	255		255		—		—		244		244		—		—
Assets held for sale(b)	—		—		—		—		101		101		—		—
Other current assets	408		404		4		—		674		669		5		—
Total current assets	1,188		1,181		7		3		1,370		1,362		8		3
Property, plant, and equipment, net	5,656		5,656		—		—		5,803		5,803		—		—
Nuclear decommissioning trust funds	3,215		3,215		—		—		3,007		3,007		—		—

Unamortized energy contract assets	237		237		—		—		249		249		—		—
Other noncurrent assets	35		26		9		9		52		42		10		10
Total noncurrent assets	9,143		9,134		9		9		9,111		9,101		10		10
Total assets(c)	$	10,331	$	10,315	$	16	$	12	$	10,481	$	10,463	$	18	$	13
Long-term debt due within one year	$	84	$	69	$	15	$	11	$	94	$	68	$	26	$	21
Accounts payable	67		67		—		—		81		81		—		—
Accrued expenses	56		56		—		—		70		70		—		—

Unamortized energy contract liabilities	1		1		—		—		4		4		—		—
Liabilities held for sale(b)	—		—		—		—		16		16		—		—
Other current liabilities	1		1		—		—		5		5		—		—
Total current liabilities	209		194		15		11		270		244		26		21
Long-term debt	860		860		—		—		889		889		—		—
Asset retirement obligations	2,377		2,377		—		—		2,318		2,318		—		—


Other noncurrent liabilities	133		133		—		—		129		129		—		—
Total noncurrent liabilities	3,370		3,370		—		—		3,336		3,336		—		—
Total liabilities(d)	$	3,579	$	3,564	$	15	$	11	$	3,606	$	3,580	$	26	$	21

_________

(a)Includes certain purchase accounting adjustments from the PHI merger not pushed down to ACE.

(b)In the fourth quarter of 2020, Generation entered into an agreement for the sale of a significant portion of Generation's solar business, and as a result of this transaction, Exelon and Generation reclassified the consolidated VIEs' solar assets and liabilities as held for sale. Completion of the transaction occurred in the first quarter of 2021. Refer to Note 2 - Mergers, Acquisitions, and Dispositions for additional information on the solar business.

(c)Exelon’s and Generation’s balances include unrestricted assets for current unamortized energy contract assets of $22 million and $22 million, non-current unamortized energy contract assets of $216 million and $249 million, assets held for sale of $0 million and $9 million, and other unrestricted assets of $0 million and $1 million as of June 30, 2021 and December 31, 2020, respectively

(d)Exelon’s and Generation’s balances include liabilities with recourse of $1 million and $8 million as of June 30, 2021 and December 31, 2020, respectively.

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

Note 17 — Variable Interest Entities

As of June 30, 2021 and December 31, 2020, Exelon's and Generation's consolidated VIEs consist of:


Consolidated VIE or VIE groups:	Reason entity is a VIE:	Reason Generation is primary beneficiary:
CENG - A joint venture between Generation and EDF. Generation has a 50.01% equity ownership in CENG. See additional discussion below.	Disproportionate relationship between equity interest and operational control as a result of the 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 has a noncontrolling interest.	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 2019.	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 6 - 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. 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. Refer to Note 2 - Mergers, Acquisitions, and Dispositions for additional information.

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 19 — Commitments and Contingencies of the Exelon 2020 Form 10-K for more details,

•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

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

Note 17 — Variable Interest Entities

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. There is limited recourse 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 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on ExGen Renewables IV.

As of June 30, 2021 and December 31, 2020, 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, 2021 and December 31, 2020, Exelon and Generation had significant unconsolidated variable interests in several VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.

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


	June 30, 2021						December 31, 2020
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	786	$	378	$	1,164	$	777	$	401	$	1,178
Total liabilities(a)	95		210		305		61		223		284
Exelon's ownership interest in VIE(a)	—		149		149		—		157		157
Other ownership interests in VIE(a)	691		19		710		716		21		737

_________

(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, 2021 and December 31, 2020.

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

Note 17 — Variable Interest Entities

As of June 30, 2021 and December 31, 2020, 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 2019.	Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation does not conduct the operational activities.
Energy Purchase and Sale agreements - Generation has several energy purchase and sale agreements with generating facilities.	PPA contracts that absorb variability through fixed pricing.	Generation does not conduct the operational activities.

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

Note 18 — Supplemental Financial Information

18. 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		PHI		DPL
Three Months Ended June 30, 2021
Operating lease income	$	13	$	12	$	1	$	1
Variable lease income	74		74		—		—

Three Months Ended June 30, 2020
Operating lease income	$	14	$	12	$	1	$	1
Variable lease income	80		79		1		1

Six Months Ended June 30, 2021
Operating lease income	$	17	$	15	$	2	$	2
Variable lease income	137		137		—		—

Six Months Ended June 30, 2020
Operating lease income	$	18	$	15	$	2	$	2
Variable lease income	149		148		1		1


	Taxes other than income taxes
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended June 30, 2021
Utility taxes(a)	$	206	$	22	$	61	$	32	$	20	$	71	$	65	$	5	$	—
Property	153		66		8		4		43		31		20		10		1
Payroll	61		30		6		4		5		7		1		1		1

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

Six Months Ended June 30, 2021
Utility taxes(a)	$	423	$	46	$	121	$	66	$	45	$	145	$	132	$	11	$	1
Property	307		133		16		9		85		63		42		19		1
Payroll	122		58		13		8		9		14		3		3		2

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

__________

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

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

Note 18 — Supplemental Financial Information


	Other, Net
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended June 30, 2021
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	144	$	144	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	87		87		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	361		361		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	193		193		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(402)		(402)		—		—		—		—		—		—		—
Decommissioning-related activities	383		383		—		—		—		—		—		—		—
AFUDC — Equity	35		—		9		6		7		12		10		1		1
Non-service net periodic benefit cost	26		—		—		—		—		—		—		—		—
Net unrealized gains from equity investments(c)	119		119		—		—		—		—		—		—		—

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		—		—		—		—		—		—		—		—

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

Note 18 — Supplemental Financial Information


	Other, net
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Six Months Ended June 30, 2021
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	435	$	435	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	290		290		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	279		279		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	126		126		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(569)		(569)		—		—		—		—		—		—		—
Decommissioning-related activities	561		561		—		—		—		—		—		—		—

AFUDC — Equity	64		—		13		12		14		25		20		3		2
Non-service net periodic benefit cost	46		—		—		—		—		—		—		—		—
Net unrealized gains from equity investments(c)	96		96		—		—		—		—		—		—		—

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		—		—		—		—		—		—		—		—

__________

(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 except for decommissioning-related impacts that were not offset for the Byron units in the second quarter of 2021, including the elimination of income taxes related to all NDT fund activity for those units. See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information regarding the accounting for nuclear decommissioning and Note 8 — Nuclear Decommissioning for additional information on the contractual offset suspension for the Byron units.

(c)Net unrealized gains from equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021.

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

Note 18 — 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, 2021
Property, plant, and equipment(a)	$	3,043	$	1,844	$	480	$	165	$	215	$	309	$	135	$	84	$	76
Amortization of regulatory assets(a)	291		—		109		8		78		95		64		20		11
Amortization of intangible assets, net(a)	29		25		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(b)	13		13		—		—		—		—		—		—		—
Nuclear fuel(c)	549		549		—		—		—		—		—		—		—
ARO accretion(d)	255		255		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	4,180	$	2,686	$	589	$	173	$	293	$	404	$	199	$	104	$	87

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

__________

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

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

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

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

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

Note 18 — Supplemental Financial Information


	Other non-cash operating activities
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Six Months Ended June 30, 2021
Pension and non-pension postretirement benefit costs	$	196	$	56	$	64	$	4	$	29	$	24	$	3	$	1	$	5
Allowance for credit losses	100		46		24		17		4		9		5		2		2
Other decommissioning-related activity(a)	(636)		(636)		—		—		—		—		—		—		—
Energy-related options(b)	20		20		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(c)	(176)		—		(64)		(17)		(8)		(88)		(46)		(19)		(23)


Long-term incentive plan	62		—		—		—		—		—		—		—		—


Amortization of operating ROU asset	83		51		1		—		15		14		3		5		2


AFUDC — Equity	(64)		—		(13)		(12)		(14)		(25)		(20)		(3)		(2)

Six Months Ended June 30, 2020
Pension and non-pension postretirement benefit costs	$	203	$	58	$	57	$	3	$	31	$	35	$	7	$	4	$	7
Allowance for credit losses	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		—		—		—		—		—		—

AFUDC — Equity	(49)		—		(14)		(7)		(10)		(17)		(13)		(2)		(2)

__________

(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units in the second quarter of 2021, 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 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information regarding the accounting for nuclear decommissioning and Note 8 — Nuclear Decommissioning for additional information on the contractual offset suspension for the Byron units.

(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, distributed generation, 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 3 — Regulatory Matters for additional information.

(d)See Note 15 — Commitments and Contingencies for additional information related to the Deferred Prosecution Agreement.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 18 — 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, 2021
Cash and cash equivalents	$	1,578	$	542	$	71	$	376	$	368	$	61	$	17	$	17	$	11
Restricted cash and cash equivalents	379		59		240		8		3		42		33		5		3
Restricted cash included in other long-term assets	52		—		43		—		—		9		—		—		9
Total cash, restricted cash, and cash equivalents	$	2,009	$	601	$	354	$	384	$	371	$	112	$	50	$	22	$	23

December 31, 2020
Cash and cash equivalents	$	663	$	226	$	83	$	19	$	144	$	111	$	30	$	15	$	17
Restricted cash and cash equivalents	438		89		279		7		1		39		35		—		3
Restricted cash included in other long-term assets	53		—		43		—		—		10		—		—		10
Cash, restricted cash, and cash equivalents - Held for Sale	12		12		—		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,166	$	327	$	405	$	26	$	145	$	160	$	65	$	15	$	30

June 30, 2020
Cash and cash equivalents	$	2,129	$	483	$	403	$	380	$	195	$	39	$	19	$	6	$	8
Restricted cash and cash equivalents	373		153		155		7		1		36		33		—		3
Restricted cash included in other long-term assets	178		—		166		—		—		11		—		—		11
Total cash, restricted cash, and cash equivalents	$	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 and cash equivalents	358		146		150		6		1		36		33		—		2
Restricted cash included in other long-term assets	177		—		163		—		—		14		—		—		14
Total cash, restricted cash, and cash equivalents	$	1,122	$	449	$	403	$	27	$	25	$	181	$	63	$	13	$	28

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2020 Form 10-K.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 18 — 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, 2021
Compensation-related accruals(a)	$	730	$	255	$	136	$	51	$	55	$	85	$	28	$	16	$	13
Taxes accrued	473		242		77		31		35		86		58		9		9
Interest accrued	339		43		116		40		45		51		27		8		12

December 31, 2020
Compensation-related accruals(a)	$	1,069	$	426	$	170	$	73	$	84	$	109	$	36	$	18	$	17
Taxes accrued	527		229		94		16		73		117		90		18		12
Interest accrued	331		44		109		37		46		51		26		7		12

__________

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

19. 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,
	2021		2020		2021		2020
Operating revenues from affiliates:
ComEd(a)(b)	$	75	$	80	$	153	$	170
PECO(c)	41		41		83		78
BGE(d)	58		70		130		169
PHI	77		78		176		182
Pepco(e)	55		60		130		139
DPL(f)	17		16		37		38
ACE(g)	5		2		9		5
Other	3		2		7		2
Total operating revenues from affiliates (Generation)	$	254	$	271	$	549	$	601

__________

(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, 2021, respectively, ComEd’s Purchased power from Generation of $78 million and $163 million is recorded as Operating revenues from ComEd of $75 million and $153 million and as Purchased power and fuel from ComEd of $3 million and $10 million at Generation. 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.

(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.

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

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

Note 19 — Related Party Transactions

(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 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.

Service Company Costs for Corporate Support

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,
	2021		2020		2021		2020		2021		2020		2021		2020
Exelon
BSC									$	124	$	129	$	282	$	242
PHISCO									17		16		36		30
Generation
BSC	$	135	$	133	$	280	$	273	10		14		33		25
ComEd
BSC	72		67		143		138		45		41		102		83
PECO
BSC	40		36		80		73		17		18		44		33
BGE
BSC	45		40		88		82		20		30		43		58
PHI
BSC	37		35		76		72		32		26		60		43
PHISCO	—		—		—		—		17		16		36		30
Pepco
BSC	23		20		45		41		13		9		25		15
PHISCO	28		32		57		62		7		7		15		13

DPL
BSC	15		13		29		26		10		9		19		14
PHISCO	24		25		49		49		5		5		11		9

ACE
BSC	12		11		24		21		8		8		15		12
PHISCO	21		23		43		44		5		4		10		8

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 19 — Related Party Transactions

Current Receivables from/Payables to affiliates

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

June 30, 2021


				Receivables from affiliates:
	Payables to affiliates:			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
Generation					$	20		$	—		$	—		$	—		$	—		$	—		$	84		$	—		$	15		$	119
ComEd		$	52	(a)				—			—			—			—			—			50			—			7			109
PECO		22			—						—			—			—			—			24			—			4			50
BGE		8			—			—						—			—			—			31			—			2			41
PHI		—			—			—			—			—			—			—			4			—			10			14
Pepco		12			—			—			—						—			—			14			14			2			42
DPL		3			—			—			—			—						—			9			10			1			23
ACE		12			—			—			—			—			—						8			10			—			30
Other		8			2			—			—			—			—			1			—			—						11
Total		$	117		$	22		$	—		$	—		$	—		$	—		$	1		$	224		$	34		$	41		$	439

December 31, 2020


				Receivables from affiliates:
	Payables to affiliates:			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
Generation					$	13		$	—		$	—		$	—		$	—		$	—		$	72		$	—		$	22		$	107
ComEd		$	78	(a)				—			—			—			—			—			59			—			9			146
PECO		17			1						—			—			—			—			28			—			4			50
BGE		11			—			—						—			—			—			47			—			3			61
PHI		—			—			—			—			—			—			—			4			—			11			15
Pepco		13			2			—			1						—			—			25			14			—			55
DPL		3			1			—			—			—						—			21			10			1			36
ACE		6			—			—			—			—			—						15			9			1			31
Other		25			5			2			2			2			1			6			—			—						43
Total		$	153		$	22		$	2		$	3		$	2		$	1		$	6		$	271		$	33		$	51		$	544

__________

(a)As of June 30, 2021 and December 31, 2020, Generation had a contract liability with ComEd for $7 million and $50 million, respectively, that was included in Other current liabilities on Generation’s Consolidated Balance Sheets. At June 30, 2021 and December 31, 2020, ComEd had a Current Payable to Generation of $45 million and $28 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

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 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 19 — Related Party Transactions

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


	June 30, 2021		December 31, 2020
ComEd	$	2,439	$	2,541
PECO	571		475

Long-term debt to financing trusts

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


	June 30, 2021						December 31, 2020
	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.

20. Planned Separation

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies. Under the separation plan, Exelon shareholders will retain their current shares of Exelon stock and receive a pro-rata distribution of shares of the new company’s stock in a transaction that is expected to be tax-free to Exelon and its shareholders for U.S. federal income tax purposes. The actual number of shares to be distributed to Exelon shareholders will be determined prior to closing.

Exelon is targeting to complete the separation in the first quarter of 2022, subject to final approval by Exelon’s Board of Directors, a Form 10 registration statement being declared effective by the SEC, regulatory approvals, and satisfaction of other conditions. The transaction is subject to approval by the FERC, NRC, and NYPSC and receipt of a private letter ruling from the IRS and tax opinion from Exelon’s tax advisors.

On February 25, 2021, Exelon and Generation filed applications with the FERC, NYPSC, and NRC seeking approvals for the separation of Generation. On March 25, 2021, Exelon filed a request for a private letter ruling with the IRS to confirm the tax-free treatment of the planned separation. Exelon and Generation expect a decision from the IRS in the third quarter of 2021, the FERC in the second half of 2021, the NRC in the fourth quarter of 2021, and have requested a decision from the NYPSC before the end of 2021. Exelon and Generation cannot predict if the applications will be approved as filed.

There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing.

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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 5 — 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.

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, 2021 compared to the same period in 2020. For additional information regarding the financial results for the three and six months ended June 30, 2021 and 2020 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
	2021		2020				2021		2020
Exelon	$	401	$	521	$	(120)	$	112	$	1,103	$	(991)
Generation	(61)		476		(537)		(854)		521		(1,375)
ComEd	192		(61)		253		390		107		283
PECO	104		39		65		271		178		93
BGE	45		39		6		254		219		35
PHI	141		94		47		269		202		67
Pepco	75		57		18		134		109		25
DPL	30		19		11		86		64		22
ACE	37		18		19		51		31		20
Other(a)	(20)		(66)		46		(218)		(124)		(94)

__________

(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, 2021 Compared to Three Months Ended June 30, 2020. Net income attributable to common shareholders decreased by $120 million and diluted earnings per average common share decreased to $0.41 in 2021 from $0.53 in 2020 primarily due to:

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•Accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024;

•Impairments of the New England asset group and the Albany Green Energy biomass facility at Generation; and

•Lower net unrealized and realized gains on NDT funds.

The decreases were partially offset by:

•Higher mark-to-market gains;

•Higher net unrealized and realized gains on equity investments;

•Lower nuclear outage days;

•Higher New York ZEC revenues due to higher generation and an increase in ZEC prices;

•Lower operating and maintenance expense at ComEd due to the payments that ComEd made in 2020 under the Deferred Prosecution Agreement;

•Higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd;

•The favorable impacts of the multi-year plan at BGE and regulatory rate increases at DPL and ACE;

•Favorable volume at PECO and ACE; and

•Lower storm costs at PECO due to the absence of the June 2020 storms.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020. Net income attributable to common shareholders decreased by $991 million and diluted earnings per average common share decreased to $0.11 in 2021 from $1.13 in 2020 primarily due to:

•Impacts of the February 2021 extreme cold weather event;

•Impairments of the New England asset group and the Albany Green Energy biomass facility at Generation; and

•The absence of a prior year one-time tax settlement.

The decreases were partially offset by:

•Higher mark-to-market gains;

•Higher net unrealized and realized gains on NDT funds;

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•Higher net unrealized and realized gains on equity investments;

•Lower nuclear outage days;

•Higher New York ZEC revenues due to higher generation and an increase in ZEC prices;

•Lower operating and maintenance expense at ComEd due to the payments that ComEd made in 2020 under the Deferred Prosecution Agreement;

•Higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd;

•The favorable impacts of the multi-year plan at BGE and regulatory rate increases at DPL and ACE;

•Favorable weather conditions at PECO, DPL's Delaware service territory, and ACE;

•Favorable volume at PECO and ACE; and

•Lower storm costs at PECO due to the absence of the June 2020 storms.

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.

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, 2021 compared to the same period in 2020.

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	Three Months Ended June 30,
	2021				2020
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net Income Attributable to Common Shareholders	$	401	$	0.41	$	521	$	0.53
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $79 and $18, respectively)	(231)		(0.24)		(51)		(0.05)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $134 and $275, respectively)(a)	(130)		(0.13)		(305)		(0.31)
Asset Impairments (net of taxes of $124 and $7, respectively)(b)	368		0.38		19		0.02
Plant Retirements and Divestitures (net of taxes of $116 and $2, respectively)(c)	344		0.35		7		0.01
Cost Management Program (net of taxes of $1 and $3, respectively)(d)	2		—		6		0.01
Change in Environmental Liabilities (net of taxes of $0)	—		—		1		—
COVID-19 Direct Costs (net of taxes of $3 and $10, respectively)(e)	9		0.01		27		0.03
Deferred Prosecution Agreement Payments (net of taxes of $0)(f)	—		—		200		0.20
Acquisition Related Costs (net of taxes of $1)(g)	2		—		—		—
ERP System Implementation Costs (net of taxes $1)(h)	2		—		—		—
Planned Separation Costs (net of taxes of $7)(i)	13		0.01		—		—
Costs Related to Suspension of Contractual Offset (net of taxes of $12)(j)	41		0.04		—		—
Income Tax-Related Adjustments (entire amount represents tax expense)	(2)		—		5		0.01
Noncontrolling Interests (net of taxes of $8 and $20, respectively)(k)	50		0.05		104		0.11
Adjusted (non-GAAP) Operating Earnings	$	869	$	0.89	$	536	$	0.55

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	Six Months Ended June 30,
	2021				2020
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net Income Attributable to Common Shareholders	$	112	$	0.11	$	1,103	$	1.13
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $125 and $50, respectively)	(366)		(0.37)		(146)		(0.15)
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $94 and $130, respectively)(a)	(87)		(0.09)		180		0.18
Asset Impairments (net of taxes of $124 and $7, respectively)(b)	368		0.38		21		0.02
Plant Retirements and Divestitures (net of taxes of $219 and $6, respectively)(c)	654		0.67		20		0.02
Cost Management Program (net of taxes of $1 and $6, respectively)(d)	4		—		17		0.02

Change in Environmental Liabilities (net of taxes of $1 and $0, respectively)	2		—		1		—
COVID-19 Direct Costs (net of taxes of $7 and $10, respectively)(e)	18		0.02		27		0.03
Deferred Prosecution Agreement Payments (net of taxes of $0)(f)	—		—		200		0.20

Acquisition Related Costs (net of tax of $3)(g)	7		0.01		—		—
ERP System Implementation Costs (net of taxes of $1)(h)	7		0.01		—		—
Planned Separation Costs (net of taxes of $7)(i)	21		0.02		—		—
Costs Related to Suspension of Contractual Offset (net of taxes of $12)(j)	41		0.04		—		—
Income Tax-Related Adjustments (entire amount represents tax expense)	(4)		—		4		—
Noncontrolling Interests (net of taxes of $3 and $10, respectively)(k)	33		0.03		(40)		(0.04)
Adjusted (non-GAAP) Operating Earnings	$	809	$	0.83	$	1,387	$	1.42

__________

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 2021 and 2020 ranged from 25.0% 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 50.6% and 47.4% for the three months ended June 30, 2021 and 2020, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 51.7% and 41.9% for the six months ended June 30, 2021 and 2020, respectively.

(a)Reflects the impact of net unrealized gains on Generation’s NDT fund investments for Non-Regulatory Agreement Units.

(b)In 2021, reflects an impairment in the New England asset group and an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility. In 2020, reflects an impairment at ComEd related to the acquisition of transmission assets and the impairment of certain wind assets at Generation.

(c)In 2021, primarily reflects accelerated depreciation and amortization associated with Generation's decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024, partially offset by a gain on sale of Generation's solar business. 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 made by ComEd under the Deferred Prosecution Agreement, which ComEd entered in July 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.

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(g)Reflects costs related to the acquisition of EDF's interest in CENG.

(h)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation.

(i)Represents costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.

(j)Decommissioning-related activities for the former ComEd and PECO units (Regulatory Agreement Units), net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s consolidated statements of operations. These costs reflect the impact of suspension of contractual offset for the Byron units in the second quarter of 2021.

(k)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.

Significant 2021 Transactions and Developments

Planned Separation

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy.

On February 25, 2021, Exelon and Generation filed applications with the FERC, NYPSC, and NRC seeking approvals for the separation of Generation. On March 25, 2021, Exelon filed a request for a private letter ruling with the IRS to confirm the tax-free treatment of the planned separation. Exelon and Generation expect a decision from the IRS in the third quarter of 2021, the FERC in the second half of 2021, the NRC in the fourth quarter of 2021, and have requested a decision from the NYPSC before the end of 2021. Exelon and Generation cannot predict if the applications will be approved as filed.

In connection with the planned separation, Exelon incurred transaction costs of approximately $19 million and $28 million on a pre-tax basis for the three and six months ended June 30, 2021, respectively, which are excluded from Adjusted (non-GAAP) Operating Earnings. The transaction costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.

There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing. See Note 20 — Planned Separation of the Combined Notes to Consolidated Financial Statements for additional information.

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages

The estimated impact to Exelon’s and Generation’s Net income for the six months ended June 30, 2021 arising from these market and weather conditions was a reduction of approximately $880 million. The estimated impact to Exelon's and Generation's Net income for the three months ended June 30, 2021 was not material. The six months ended estimated impact includes certain charges associated with the natural gas business that may be reduced through waivers and/or recoveries from customers. Therefore, such charges are not included in the estimated full year earnings impact. Exelon and Generation estimate a reduction in Net income of approximately $670 million to $820 million for the full year 2021. The ultimate impact to Exelon’s and Generation’s consolidated financial statements may be affected by a number of factors, including final settlement data, the impacts of customer and counterparty credit losses, any state or federal solutions to address the financial challenges caused by the event, and related litigation and contract disputes. See Note 3 — Regulatory Matters and Note 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Exelon expects to offset between $410 million and $490 million of this impact for the full year 2021 primarily at Generation through a combination of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings.

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Agreement for the Sale of a Generation Biomass Facility

On April 28, 2021, Generation and ReGenerate entered into a purchase agreement, under which ReGenerate agreed to purchase Generation's interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, Exelon and Generation recorded a pre-tax impairment charge of $140 million which is excluded from Exelon’s and Generation’s Adjusted (non-GAAP) Operating Earnings. The sale was completed on June 30, 2021 for a net purchase price of $36 million. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

Early Retirement of Generation Facilities

In August 2020, Generation announced that it intends to retire the Byron Generating Station in September 2021, Dresden Generating Station in November 2021, and Mystic Units 8 and 9 at the expiration of the cost of service commitment in May 2024. As a result, there are ongoing annual financial impacts stemming from shortening the expected economic useful lives of these facilities, primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel.

Also, as a result, in the third quarter of 2020, Exelon and Generation recognized a $500 million pre-tax impairment for the New England asset group. In the second quarter of 2021, an incremental decline in value resulted in an additional pre-tax impairment charge of $350 million for the New England asset group. See Note 9 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information.

Further, in the second quarter of 2021, Exelon and Generation recorded a pre-tax charge of $53 million for decommissioning-related activities that were not offset for the Byron units due to the inability to recognize a regulatory asset at ComEd. In the event Byron retires in September 2021 as previously announced, the full year impact is estimated to be in the range of $450 million to $600 million, depending on future market returns. See Note 7 — Early Plant Retirements and Note 8 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

All of the charges above are excluded from Exelon's and Generation’s Adjusted (non-GAAP) Operating Earnings.

The following table summarizes the incremental expense recorded in the three and six months ended June 30, 2021 and the estimated amounts of incremental expense expected to be incurred for the full year 2021 and through the retirement dates.


	Actual				Projected(a)
Income statement expense (pre-tax)	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021		2021		2022		2023		2024
Depreciation and amortization
Accelerated depreciation(b)	$	632	$	1,271	$	2,770	$	10	$	20	$	10
Accelerated nuclear fuel amortization	52		106		180		—		—		—
Operating and maintenance

Other charges	2		4		20		10		10		30

Contractual offset(c)	(166)		(391)		(930)		—		—		—
Total	$	520	$	990	$	2,040	$	20	$	30	$	40

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__________

(a)Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc. and exclude any changes in earnings in the NDT funds.

(b)Reflects incremental accelerated depreciation of plant assets, including any ARC.

(c)Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO for Byron and Dresden and exclude any changes in earnings in the NDT funds. Decommissioning-related activities were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activities result in a regulatory liability at ComEd. Recognition of a regulatory asset for nuclear decommissioning-related activities at ComEd is not permissible. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 8 – Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

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 2021. See Note 3 — 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	Service	Requested Revenue Requirement (Decrease) Increase		Approved Revenue Requirement (Decrease) Increase		Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois	April 16, 2020	Electric	$	(11)	$	(14)	8.38	%	December 9, 2020	January 1, 2021
PECO - Pennsylvania	September 30, 2020	Natural Gas	69		29		10.24	%	June 22, 2021	July 1, 2021
BGE - Maryland	May 15, 2020 (amended September 11, 2020)	Electric	203		140		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	108		74		9.65	%
Pepco - District of Columbia	May 30, 2019 (amended June 1, 2020)	Electric	136		109		9.275	%	June 8, 2021	July 1, 2021
Pepco - Maryland	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021

ACE - New Jersey	December 9, 2020 (amended February 26, 2021)	Electric	67		41		9.60	%	July 14, 2021	January 1, 2022

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Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

ComEd - Illinois

April 16, 2021

Electric

7.36

Fourth quarter of 2021

PECO - Pennsylvania

March 30, 2021

Electric

246

10.95

Fourth quarter of 2021

DPL - Delaware

March 6, 2020 (amended February 2, 2021)

Electric

10.3

Third quarter of 2021

Transmission Formula Rates

The following total increases/(decreases) were included in the Utility Registrants' 2021 electric transmission formula rate updates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.


Registrant	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation Increase		Total Revenue Requirement Increase		Allowed Return on Rate Base		Allowed ROE
ComEd	$	33	$	12	$	45	8.20	%	11.50	%
PECO	(2)		26		24		7.37	%	10.35	%
BGE	38		27		65		7.35	%	10.50	%
Pepco	(9)		21		12		7.68	%	10.50	%
DPL	19		33		52		7.20	%	10.50	%
ACE	27		24		51		7.45	%	10.50	%

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 2020 Form 10-K and Note 15 — Commitments and Contingencies to the Consolidated Financial Statements in this report for additional information on various environmental matters.

Power Markets

Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps

On February 21, 2019, PJM's Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM claims that this allows for the exercise of market power. The IMM asks FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. Several consumer advocates filed a complaint seeking similar relief several months after the IMM’s complaint. On March 18, 2021, FERC granted the complaints, finding the current estimate of performance assessment intervals to be excessive compared to the reasonably expected number of performance assessment intervals which results in an unjust and unreasonable default offer cap. FERC did not establish the number of performance assessment intervals that should be used to calculate the default offer cap and instead requested briefs on the matter, including alternative approaches to mitigation in the capacity market. Exelon submitted an initial and reply briefs on May 3, 2021 and June 9, 2021, respectively, and an answer to briefs filed by other parties on June 24, 2021. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation.

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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, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 98%-101% for 2021. 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 2021 through 2025 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 consolidated financial statements.

See Note 12 — 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 Regulation

Exelon is well positioned to support increasingly ambitious climate policy and to partner with our customers and communities to reduce GHG emissions.

In August 2021, the Utility Registrants announced a “path to clean” goal to collectively reduce their operations-driven emissions 50% by 2030 against a 2015 baseline, and to reach net zero operations-driven emissions by 2050. This goal builds upon Exelon’s long-standing commitment to reducing our GHG emissions. The Utility Registrants “path to clean” will include efficiency and clean electricity for operations, vehicle fleet electrification, equipment and processes to reduce sulfur hexafluoride (SF6) leakage, modern natural gas infrastructure to minimize methane leaks and increase safety and reliability, and investment and collaboration to develop new technologies.

Generation produces electricity predominantly from low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind, and solar PV) and neither owns nor operates any coal-fueled generating assets. Generation’s natural gas and biomass fired generating plants produce GHG emissions, most notably CO2. However, Generation’s owned-asset emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry.

The United States has set an economy-wide target of reducing its net GHG emissions by 50-52% below 2005 levels by 2030.

Other Legislative and Regulatory Developments

FERC Supplemental Notice of Proposed Rulemaking

On April 15, 2021, the FERC issued a Supplemental Notice of Proposed Rulemaking (NOPR) proposing to modify the current regulation permitting a continuous 50-basis-point ROE incentive adder for a transmission utility that joins and remains a member of a RTO. Under the NOPR, the ROE incentive adder would only be available for a period of up to three years after a transmission utility newly joins a RTO and all existing ROE incentive adders would end for transmission utilities that have been members for three or more years. The Utility

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Registrants’ existing transmission rates include the ROE incentive adder. Exelon submitted comments to FERC on this matter on June 25, 2021. Exelon cannot predict the outcome, but a final rule as proposed could have an adverse impact to Exelon’s and the Utility Registrants’ financial statements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the Utility Registrants’ transmission formula rates and regulatory proceedings at the FERC.

City of Chicago Franchise Agreement

ComEd has had a Franchise Agreement with the City of Chicago (the City) since 1992. The Franchise Agreement grants rights to use the public right of way to install, maintain, and operate the wires, poles, and other infrastructure required to deliver electricity to residents and businesses across the City. The Franchise Agreement became terminable on one year notice as of December 31, 2020. It now continues in effect indefinitely unless and until either party issues a notice of termination, effective one year later, or it is replaced by mutual agreement with a new franchise agreement between ComEd and the City. If either party terminates and no new agreement is reached between the parties, the parties could continue with ComEd providing electric services within the City with no franchise agreement in place. The City also has an option to terminate and purchase the ComEd system (“municipalize”), which also requires one year notice. Neither party has issued a notice of termination at this time, the City has not exercised its municipalization option, and no new agreement has been reached. Accordingly, the 1992 Franchise Agreement remains in effect at this time. In April 2021, the City invited interested parties to respond to a Request for Information (RFI) regarding the franchise for electricity delivery. Under this process, the City could choose to terminate the ComEd Franchise Agreement on one year notice and grant a franchise to another party instead. Final responses to the RFI were due on July 30, 2021, however, on July 29, 2021, the City chose to extend the final submission deadline to September 30, 2021. While Exelon and ComEd cannot predict the ultimate outcome of the RFI and the Franchise Agreement, fundamental changes in the agreement or other adverse actions affecting ComEd’s business in the City would require changes in their business planning models and operations and could have a material adverse impact on Exelon’s and ComEd’s consolidated financial statements. If the City were to disconnect from the ComEd system, ComEd would seek full compensation for the business and its associated property taken by the City, as well as for all damages resulting to ComEd and its system. ComEd would also seek appropriate compensation for stranded costs with the FERC.

Employees

In the second quarter of 2021, Generation and PECO ratified CBAs as follows:

•Generation ratified its CBA with UGSOA, which covers 73 security officers at Three Mile Island. The CBA will expire in 2023.

•PECO ratified two CBAs with IBEW Local 614 which covers 1,140 operations employees and 185 customer service employees, respectively. Both CBAs expire in 2026.

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, 2021, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2020. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the Registrants' 2020 Form 10-K for further information.

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Results of Operations by Registrant

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,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	4,153	$	3,880	$	273	$	9,712	$	8,613	$	1,099
Purchased power and fuel expense	1,947		1,942		(5)		6,557		4,646		(1,911)
Revenues net of purchased power and fuel expense	2,206		1,938		268		3,155		3,967		(812)
Other operating expenses
Operating and maintenance	1,474		1,189		(285)		2,476		2,451		(25)
Depreciation and amortization	930		300		(630)		1,869		604		(1,265)
Taxes other than income taxes	118		116		(2)		239		246		7
Total other operating expenses	2,522		1,605		(917)		4,584		3,301		(1,283)

Gain on sales of assets and businesses	8		12		(4)		79		12		67


Operating (loss) income	(308)		345		(653)		(1,350)		678		(2,028)
Other income and (deductions)
Interest expense, net	(76)		(87)		11		(148)		(197)		49
Other, net	508		602		(94)		675		(168)		843
Total other income and (deductions)	432		515		(83)		527		(365)		892
Income (loss) before income taxes	124		860		(736)		(823)		313		(1,136)
Income taxes	110		329		219		(70)		(59)		11
Equity in losses of unconsolidated affiliates	(1)		(2)		1		(3)		(4)		1
Net income (loss)	13		529		(516)		(756)		368		(1,124)
Net income (loss) attributable to noncontrolling interests	74		53		21		98		(153)		251
Net (loss) income attributable to membership interest	$	(61)	$	476	$	(537)	$	(854)	$	521	$	(1,375)

Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020. Net income attributable to membership interest decreased by $537 million primarily due to:

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•Accelerated depreciation and amortization associated with Generation's decisions in the third quarter of
2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024;

•Impairments of the New England asset group and the Albany Green Energy biomass facility at
Generation; and

•Lower net unrealized and realized gains on NDT funds.

The decreases were partially offset by:

•Higher mark-to-market gains;

•Higher net unrealized and realized gains on equity investments;

•Lower nuclear outage days; and

•Higher New York ZEC revenues due to higher generation and an increase in ZEC prices.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020. Net income attributable to membership interest decreased by $1,375 million primarily due to:

•Impacts of the February 2021 extreme cold weather event;

•Accelerated depreciation and amortization associated with Generation's decisions in the third quarter of
2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024;

•Impairments of the New England asset group and the Albany Green Energy biomass facility at
Generation; and

•The absence of a prior year one-time tax settlement.

The decreases were partially offset by:

•Higher mark-to-market gains;

•Higher net unrealized and realized gains on NDT funds;

•Higher net unrealized and realized gains on equity investments;

•Lower nuclear outage days; and

•Higher New York ZEC revenues due to higher generation and an increase in ZEC prices.

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 5 - 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,

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and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.

For the three and six months ended June 30, 2021 compared to 2020, RNF by region were as follows. See Note 5 - 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
	2021		2020						2021		2020
Mid-Atlantic(a)	$	572	$	525	$	47	9.0	%	$	1,141	$	1,092	$	49	4.5	%
Midwest(b)	658		703		(45)		(6.4)	%	1,360		1,427		(67)		(4.7)	%
New York	292		246		46		18.7	%	536		440		96		21.8	%
ERCOT	83		97		(14)		(14.4)	%	(1,102)		177		(1,279)		(722.6)	%
Other Power Regions	136		157		(21)		(13.4)	%	353		312		41		13.1	%
Total electric revenues net of purchased power and fuel expense	1,741		1,728		13		0.8	%	2,288		3,448		(1,160)		(33.6)	%
Mark-to-market gains	314		85		229		269.4	%	489		218		271		124.3	%
Other	151		125		26		20.8	%	378		301		77		25.6	%
Total revenue net of purchased power and fuel expense	$	2,206	$	1,938	$	268	13.8	%	$	3,155	$	3,967	$	(812)	(20.5)	%

__________

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

(b)Includes results of transactions with ComEd.

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Generation’s supply sources by region are summarized below:


	Three Months Ended June 30,		Variance	% Change		Six Months Ended June 30,		Variance	% Change
Supply Source (GWhs)	2021	2020				2021	2020
Nuclear Generation(a)
Mid-Atlantic	13,197	13,167	30	0.2	%	26,451	25,951	500	1.9	%
Midwest	23,299	23,860	(561)	(2.4)	%	46,454	47,458	(1,004)	(2.1)	%
New York	7,079	6,389	690	10.8	%	14,135	12,562	1,573	12.5	%
Total Nuclear Generation	43,575	43,416	159	0.4	%	87,040	85,971	1,069	1.2	%
Fossil and Renewables
Mid-Atlantic	522	707	(185)	(26.2)	%	1,185	1,560	(375)	(24.0)	%
Midwest	262	268	(6)	(2.2)	%	585	656	(71)	(10.8)	%
New York	—	1	(1)	(100.0)	%	1	2	(1)	(50.0)	%
ERCOT	2,797	3,251	(454)	(14.0)	%	5,581	6,263	(682)	(10.9)	%
Other Power Regions	2,239	2,603	(364)	(14.0)	%	5,205	6,110	(905)	(14.8)	%
Total Fossil and Renewables	5,820	6,830	(1,010)	(14.8)	%	12,557	14,591	(2,034)	(13.9)	%
Purchased Power
Mid-Atlantic	3,089	3,730	(641)	(17.2)	%	7,571	9,672	(2,101)	(21.7)	%
Midwest	131	236	(105)	(44.5)	%	310	524	(214)	(40.8)	%

ERCOT	1,259	1,255	4	0.3	%	2,031	2,246	(215)	(9.6)	%
Other Power Regions	12,356	11,303	1,053	9.3	%	25,189	23,469	1,720	7.3	%
Total Purchased Power	16,835	16,524	311	1.9	%	35,101	35,911	(810)	(2.3)	%
Total Supply/Sales by Region
Mid-Atlantic(b)	16,808	17,604	(796)	(4.5)	%	35,207	37,183	(1,976)	(5.3)	%
Midwest(b)	23,692	24,364	(672)	(2.8)	%	47,349	48,638	(1,289)	(2.7)	%
New York	7,079	6,390	689	10.8	%	14,136	12,564	1,572	12.5	%
ERCOT	4,056	4,506	(450)	(10.0)	%	7,612	8,509	(897)	(10.5)	%
Other Power Regions	14,595	13,906	689	5.0	%	30,394	29,579	815	2.8	%
Total Supply/Sales by Region	66,230	66,770	(540)	(0.8)	%	134,698	136,473	(1,775)	(1.3)	%

__________

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

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

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For the three and six months ended June 30, 2021 compared to 2020, changes in RNF by region were as follows:



	Increase/(Decrease)		Three Months Ended June 30, 2021	Increase/(Decrease)		Six Months Ended June 30, 2021
Mid-Atlantic	$	47	• favorable settlement of an outstanding regulatory matter • increased capacity revenue, offset by • decreased load served	$	49	• favorable settlement of an outstanding regulatory matter • increased capacity revenue • decreased nuclear outage days • increased ZEC revenues due to decreased nuclear outage days, offset by • decreased load served
Midwest	(45)		• decreased total ISO sales due to decreased generation • decreased capacity revenue, partially offset by • increased load served	(67)		• decreased load served • decreased total ISO sales due to decreased generation
New York	46		• increased ZEC revenues due to decreased nuclear outage days and higher ZEC prices • decreased nuclear outage days • increased capacity revenue • increased load served	96		• increased ZEC revenues due to decreased nuclear outage days and higher ZEC prices • decreased nuclear outage days • increased capacity revenue • increased load served
ERCOT	(14)		• higher energy procurement costs due to increased outage days	(1,279)		• higher energy procurement costs due to the February 2021 extreme cold weather event, as well as the impact of ERCOT market participant defaults • higher procurement costs due to increased outage days
Other Power Regions	(21)		• decreased capacity revenue, partially offset by • increased load served • higher portfolio optimization	41		• increased load served • higher portfolio optimization, partially offset by • decreased capacity revenue
Mark-to-market(a)	229		• gains on economic hedging activities of $314 million in 2021 compared to gains of $85 million in 2020	271		• gains on economic hedging activities of $489 million in 2021 compared to gains of $218 million in 2020
Other	26		• higher natural gas RNF due to higher natural gas prices and favorable LDC penalty waivers and revenue true ups related to the February 2021 extreme cold weather event • increased revenue related to the energy efficiency business, partially offset by • increase in accelerated nuclear fuel amortization associated with announced early plant retirements	77		• higher natural gas RNF due to higher portfolio optimization and higher natural gas prices, partially offset by penalties associated with operational flow orders and curtailments as a result of the February 2021 extreme cold weather event • increased revenue related to the energy efficiency business, partially offset by • increase in accelerated nuclear fuel amortization associated with announced early plant retirements
Total	$	268		$	(812)

__________

(a)See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains.

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

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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,
	2021		2020		2021		2020
Nuclear fleet capacity factor	93.7	%	95.4	%	94.5	%	94.7	%
Refueling outage days	66		92		150		186
Non-refueling outage days	7		—		10		11

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


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	Increase (Decrease)		Increase (Decrease)
Asset impairments	$	481	$	479
Labor, other benefits, contracting, and materials	24		(4)
Credit loss expense	(4)		43
Corporate allocations	(6)		(11)
Nuclear refueling outage costs, including the co-owned Salem plants	(37)		(88)
Plant retirements and divestitures(a)	(171)		(391)
Other	(2)		(3)
Total increase	$	285	$	25

__________

(a)Primarily reflects contractual offset of accelerated depreciation and amortization associated with Generation's decision to early retire the Byron and Dresden nuclear facilities. See Note 8 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

Depreciation and amortization expense for the three and six months ended June 30, 2021 compared to the same period in 2020 increased primarily due to the accelerated depreciation and amortization associated with Generation's decision to early retire the Byron and Dresden nuclear facilities. A portion of this accelerated depreciation and amortization is offset within Operating and maintenance expense.

Gain on sales of assets and businesses for the six months ended June 30, 2021 compared to the same period in 2020 increased primarily due to a gain on sale of Generation's solar business.

Interest Expense for the six months ended June 30, 2021 compared to the same period in 2020 decreased primarily due to mark-to-market gains related to the EGR IV interest swaps entered into in December 2020 and decreases in interest rates. See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on the interest swaps.

Other, net for the three months ended June 30, 2021 compared to the same period in 2020 decreased and for the six months ended June 30, 2021 compared to the same period in 2020 increased due to activity described in the table below:

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	Three Months Ended June 30,				Six Months Ended June 30,
	2021		2020		2021		2020
Net unrealized gains (losses) on NDT funds(a)	$	195	$	452	$	128	$	(253)
Net realized gains on sale of NDT funds(a)	63		3		248		58
Interest and dividend income on NDT funds(a)	28		19		46		46
Contractual elimination of income tax expense(b)	97		134		139		(43)
Net unrealized gains from equity investments(c)	119		—		96		—
Other	6		(6)		18		24
Total other, net	$	508	$	602	$	675	$	(168)

__________

(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.

(c)Net unrealized gains from equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021.

Effective income tax rates were 88.7% and 38.3% for the three months ended June 30, 2021 and 2020, respectively, and 8.5% and (18.8)% for the six months ended June 30, 2021 and 2020, respectively. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information

Net income attributable to noncontrolling interests for the three and six months ended June 30, 2021 compared to the same period in 2020 increased primarily due to higher net gains on NDT fund investments for CENG.

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Results of Operations — ComEd


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	1,517	$	1,417	$	100	$	3,052	$	2,856	$	196
Operating expenses
Purchased power expense	500		464		(36)		1,025		951		(74)
Operating and maintenance	323		536		213		639		853		214
Depreciation and amortization	296		274		(22)		589		547		(42)
Taxes other than income taxes	77		71		(6)		153		146		(7)
Total operating expenses	1,196		1,345		149		2,406		2,497		91

Operating income	321		72		249		646		359		287
Other income and (deductions)
Interest expense, net	(98)		(98)		—		(193)		(192)		(1)
Other, net	15		11		4		22		22		—
Total other income and (deductions)	(83)		(87)		4		(171)		(170)		(1)
Income (loss) before income taxes	238		(15)		253		475		189		286
Income taxes	46		46		—		85		82		(3)
Net income (loss)	$	192	$	(61)	$	253	$	390	$	107	$	283

Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020. Net income increased $253 million as compared to the same period in 2020, primarily due to payments that ComEd made in 2020 under the Deferred Prosecution Agreement. The remaining increase is due to electric distribution formula rate earnings (reflecting the impacts of higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates). See Note 15 - Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020. Net income increased $283 million as compared to the same period in 2020, primarily due to payments that ComEd made in 2020 under the Deferred Prosecution Agreement. The remaining increase is due to electric distribution formula rate earnings (reflecting the impacts of higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates). See Note 15 - Commitments and Contingencies of the Combined Notes to the 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, 2021		Six Months Ended June 30, 2021
	Increase		Increase
Distribution	$	52	$	73
Transmission	1		4
Energy efficiency	12		24
Other	—		12




	65		113
Regulatory required programs	35		83
Total increase	$	100	$	196

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 the revenue decoupling mechanisms as allowed by 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

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in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased for the three and six months ended June 30, 2021 as compared to the same period in 2020, due to higher allowed ROE due to an increase in treasury rates and the impact of a higher rate base.

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.

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, 2021 as compared to the same period in 2020, primarily due to increased regulatory asset amortization, which is fully recoverable.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue remained the same for the three months ended June 30, 2021 and increased for the six months ended June 30, 2021 as compared to the same period in 2020, which primarily reflects mutual assistance revenues associated with storm restoration efforts.

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 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 as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore ComEd does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

The increase of $36 million and of $74 million for the three and six months ended June 30, 2021 compared to the same period in 2020, respectively, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	(Decrease) Increase		(Decrease) Increase
Deferred Prosecution Agreement payments(a)	$	(200)	$	(200)
Storm-related costs	(5)		(14)
Pension and non-pension postretirement benefits expense	1		2
Labor, other benefits, contracting and materials	2		10

BSC costs	5		5

Other(b)	(17)		(23)
	(214)		(220)
Regulatory required programs(c)	1		6
Total decrease	$	(213)	$	(214)

__________

(a)See Note 15 - Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements for additional information.

(b)Primarily reflects the absence of an impairment charge related to acquisition of transmission assets in 2020.

(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.

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


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	Increase		Increase
Depreciation and amortization(a)	$	10	$	22
Regulatory asset amortization(b)	12		20

Total increase	$	22	$	42

__________

(a)Reflects ongoing capital expenditures.

(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset and amortization related to the August 2020 storm regulatory asset.

Effective income tax rates were 19.3% and (306.7)% for the three months ended June 30, 2021 and 2020, respectively, and 17.9% and 43.4% for the six months ended June 30, 2021 and 2020, respectively. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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Results of Operations — PECO


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	693	$	681	$	12	$	1,582	$	1,493	$	89
Operating expenses
Purchased power and fuel expense	207		216		9		523		499		(24)
Operating and maintenance	209		275		66		443		492		49
Depreciation and amortization	87		88		1		173		173		—
Taxes other than income taxes	49		39		(10)		92		78		(14)
Total operating expenses	552		618		66		1,231		1,242		11

Operating income	141		63		78		351		251		100
Other income and (deductions)
Interest expense, net	(42)		(36)		(6)		(80)		(71)		(9)
Other, net	7		5		2		12		7		5
Total other income and (deductions)	(35)		(31)		(4)		(68)		(64)		(4)
Income before income taxes	106		32		74		283		187		96
Income taxes	2		(7)		(9)		12		9		(3)


Net income	$	104	$	39	$	65	$	271	$	178	$	93

Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020. Net income increased by $65 million primarily reflects the absence of costs in 2021 due to the June 2020 storms and an increase in both gas and electric volume.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020. Net income increased by $93 million primarily reflects the absence of costs in 2021 due to the June 2020 storms, favorable weather, and an increase in primarily electric volume.

The changes in Operating revenues consisted of the following:


	Three Months Ended June 30, 2021						Six Months Ended June 30, 2021
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	3	$	(5)	$	(2)	$	24	$	12	$	36
Volume	6		5		11		17		6		23
Pricing	4		(4)		—		(3)		(4)		(7)
Transmission	2		—		2		3		—		3
Other	—		—		—		(1)		—		(1)
	15		(4)		11		40		14		54
Regulatory required programs	10		(9)		1		41		(6)		35
Total increase	$	25	$	(13)	$	12	$	81	$	8	$	89

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, 2021 compared to the same period in 2020, Operating revenues related to weather remained relatively consistent. During the six months ended June 30, 2021 compared to the same period in 2020, revenues related to weather increased by the impact of favorable 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-

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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, 2021 compared to the same period in 2020 and normal weather consisted of the following:


Heating and Cooling Degree-Days			Normal	% Change
Three Months Ended June 30,	2021	2020		From 2020		2021 vs. Normal
Heating Degree-Days	404	568	423	(28.9)	%	(4.5)	%
Cooling Degree-Days	418	376	388	11.2	%	7.7	%
			Normal	% Change
Six Months Ended June 30,	2021	2020		From 2020		2021 vs. Normal
Heating Degree-Days	2,706	2,557	2,840	5.8	%	(4.7)	%
Cooling Degree-Days	423	376	389	12.5	%	8.7	%

Volume. Electric volume, exclusive of the effects of weather, for the three and six months ended June 30, 2021, compared to the same period in 2020, increased on a net basis due to an increase in overall usage for customers further increased by customer growth. Natural gas volume for the three and six months ended June 30, 2021 compared to the same period in 2020, increased due to retail load growth.


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)
	2021	2020					2021	2020
Residential	3,116	3,143	(0.9)	%	(1.9)	%	6,883	6,397	7.6	%	2.5	%
Small commercial & industrial	1,758	1,571	11.9	%	10.8	%	3,639	3,476	4.7	%	1.9	%
Large commercial & industrial	3,475	3,181	9.2	%	8.3	%	6,747	6,602	2.2	%	1.4	%
Public authorities & electric railroads	121	112	8.0	%	8.2	%	270	263	2.7	%	2.7	%
Total electric retail deliveries(a)	8,470	8,007	5.8	%	4.8	%	17,539	16,738	4.8	%	1.9	%


	As of June 30,
Number of Electric Customers	2021	2020
Residential	1,513,456	1,501,259
Small commercial & industrial	154,842	154,016
Large commercial & industrial	3,108	3,096
Public authorities & electric railroads	10,285	10,119
Total	1,681,691	1,668,490

__________

(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)
	2021	2020					2021	2020
Residential	5,027	6,464	(22.2)	%	(9.7)	%	25,701	23,746	8.2	%	0.2	%
Small commercial & industrial	3,121	2,054	51.9	%	76.9	%	13,291	10,863	22.4	%	10.7	%
Large commercial & industrial	2	3	(33.3)	%	27.1	%	9	12	(25.0)	%	11.1	%
Transportation	5,468	5,148	6.2	%	8.6	%	13,118	12,283	6.8	%	3.6	%
Total natural gas retail deliveries(a)	13,618	13,669	(0.4)	%	9.9	%	52,119	46,904	11.1	%	3.6	%

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	As of June 30,
Number of Natural Gas Customers	2021	2020
Residential	494,895	489,201
Small commercial & industrial	44,450	44,189
Large commercial & industrial	6	6
Transportation	677	719
Total	540,028	534,115

__________

(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, 2021 compared to the same period in 2020 remained relatively consistent. Pricing for the six months ended June 30, 2021 compared to the same period in 2020 decreased primarily due to lower overall effective electric rates due to increased usage across all major customer classes.

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.

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 as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.

Other revenue which primarily includes revenue related to late payment charges. Other revenues for the three and six months ended June 30, 2021 compared to the same period in 2020, remained relatively consistent.

See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

The decrease of $9 million and the increase of $24 million for the three and six months ended June 30, 2021 compared to the same period in 2020, respectively, in Purchased power and fuel expense is partially offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	Increase (Decrease)		Increase (Decrease)
Storm-related costs(a)	$	(65)	$	(59)
Credit loss expense	(19)		(12)
Regulatory Required Programs	1		(1)
BSC costs	5		7
Labor, other benefits, contracting and materials	13		22
Other	(1)		(6)









Total increase	$	(66)	$	(49)

__________

(a)Primarily reflects the absence of costs in 2021 due to the June 2020 storms.

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


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	(2)	$	(6)
Regulatory asset amortization	3		6

Total increase	$	1	$	—

__________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Interest expense, net increased $6 million and $9 million for the three and six months ended June 30, 2021 compared to the same period in 2020, respectively, primarily due to the issuance of debt in March 2021 and June 2020.

Effective income tax rates were 1.9% and (21.9)% for the three months ended June 30, 2021 and 2020 respectively, and 4.2% and 4.8% for the six months ended June 30, 2021 and 2020, respectively. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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BGE

Results of Operations — BGE


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	682	$	616	$	66	$	1,656	$	1,554	$	102
Operating expenses
Purchased power and fuel expense	219		194		(25)		550		483		(67)
Operating and maintenance	193		187		(6)		390		376		(14)
Depreciation and amortization	141		129		(12)		293		272		(21)
Taxes other than income taxes	67		63		(4)		139		132		(7)
Total operating expenses	620		573		(47)		1,372		1,263		(109)

Operating income	62		43		19		284		291		(7)
Other income and (deductions)
Interest expense, net	(34)		(32)		(2)		(67)		(64)		(3)
Other, net	9		6		3		16		10		6
Total other income and (deductions)	(25)		(26)		1		(51)		(54)		3
Income before income taxes	37		17		20		233		237		(4)
Income taxes	(8)		(22)		(14)		(21)		18		39
Net income	$	45	$	39	$	6	$	254	$	219	$	35

Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020. Net Income increased $6 million primarily due to the favorable impacts of the multi-year plan. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plan.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020. Net income increased by $35 million primarily due to favorable impacts of the multi-year plan. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plan.

The changes in Operating revenues consisted of the following:


	Three Months Ended June 30, 2021						Six Months Ended June 30, 2021
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Distribution	$	5	$	3	$	8	$	6	$	1	$	7
Transmission	26		—		26		30		—		30
Other	5		2		7		(2)		1		(1)
	36		5		41		34		2		36
Regulatory required programs	17		8		25		40		26		66
Total increase	$	53	$	13	$	66	$	74	$	28	$	102

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

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	As of June 30,
Number of Electric Customers	2021	2020
Residential	1,192,135	1,185,718
Small commercial & industrial	114,682	114,118
Large commercial & industrial	12,528	12,416
Public authorities & electric railroads	267	264
Total	1,319,612	1,312,516


	As of June 30,
Number of Natural Gas Customers	2021	2020
Residential	647,534	643,745
Small commercial & industrial	38,223	38,255
Large commercial & industrial	6,132	6,079
Total	691,889	688,079

Distribution Revenue increased for the three and six months ended June 30, 2021, compared to the same period in 2020, due to customer growth.

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 increased for the three and six months ended June 30, 2021, compared to the same period in 2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilities.

Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other revenues increased for the three months ended June 30, 2021, compared to the same period in 2020, as BGE had temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for customers in 2020 which has resumed in 2021. Other revenues remained relatively consistent for the six months ended June 30, 2021 compared to the same period in 2020.

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 as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore BGE does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.

See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

The increase of $25 million and $67 million for the three and six months ended June 30, 2021 compared to the same period in 2020, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting, and materials	$	3	$	3
Storm-related costs	1		7

BSC costs	4		6
Credit loss expense	(4)		(6)
Other	1		2
	5		12
Regulatory required programs	1		2

Total increase	$	6	$	14

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


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	Increase		Increase
Depreciation and amortization(a)	$	10	$	19
Regulatory asset amortization	2		2


Total increase	$	12	$	21

__________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were (21.6)% and (129.4)% for the three months ended June 30, 2021 and 2020, respectively, and (9.0)% and 7.6% for the six months ended June 30, 2021 and 2020, respectively. The change is primarily due to the multi-year plan which resulted in the acceleration of certain income tax benefits and the April 24, 2020 settlement agreement of ongoing transmission related income tax regulatory liabilities. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plan, Note 3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement, and Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PHI

Results of Operations — PHI

PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net Income by Registrant for the three and six months ended June 30, 2021 compared to the same period in 2020. See the Results of Operations for Pepco, DPL, and ACE for additional information.


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
PHI	$	141	$	94	$	47	$	269	$	202	$	67
Pepco	75		57		18		134		109		25
DPL	30		19		11		86		64		22
ACE	37		18		19		51		31		20
Other(a)	(1)		—		(1)		(2)		(2)		—

_________

(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, 2021 Compared to Three Months Ended June 30, 2020. Net Income increased by $47 million primarily due to higher electric distribution rates at DPL, higher transmission revenues due to an increase in capital investments and higher distribution revenues due to an increase in volume in ACE's service territory, customer growth at Pepco, and a decrease in credit loss expense at Pepco and DPL.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020. Net Income increased by $67 million primarily due higher electric distribution rates at DPL, favorable weather conditions in DPL's Delaware and ACE's service territories, higher transmission revenues due to an increase in capital investments and higher distribution revenues due to an increase in volume in ACE's service territory, customer growth at Pepco, and a decrease in credit loss expense at Pepco and DPL.

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Results of Operations — Pepco


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	523	$	494	$	29	$	1,076	$	1,039	$	37


Operating expenses
Purchased power expense	133		138		5		298		303		5
Operating and maintenance	113		119		6		221		231		10
Depreciation and amortization	96		92		(4)		199		186		(13)
Taxes other than income taxes	87		87		—		177		179		2
Total operating expenses	429		436		7		895		899		4

Operating income	94		58		36		181		140		41
Other income and (deductions)
Interest expense, net	(35)		(34)		(1)		(69)		(68)		(1)
Other, net	13		9		4		25		18		7
Total other income and (deductions)	(22)		(25)		3		(44)		(50)		6
Income before income taxes	72		33		39		137		90		47
Income taxes	(3)		(24)		(21)		3		(19)		(22)
Net income	$	75	$	57	$	18	$	134	$	109	$	25

Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020. Net income increased $18 million primarily due to customer growth, a decrease in credit loss expense, and decreases in various operating expenses.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020. Net income increased $25 million primarily due to customer growth, a decrease in credit loss expense, and decreases in various operating expenses.

The changes in Operating revenues consisted of the following:


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	Increase (Decrease)		Increase (Decrease)
Distribution	$	1	$	4
Transmission	25		22
Other	(2)		—
	24		26
Regulatory required programs	5		11
Total increase	$	29	$	37

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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	As of June 30,
Number of Electric Customers	2021	2020
Residential	837,744	825,000
Small commercial & industrial	53,669	53,809
Large commercial & industrial	22,579	22,467
Public authorities & electric railroads	178	168
Total	914,170	901,444

Distribution Revenue remained relatively consistent for the three months ended June 30, 2021 compared to the same period in 2020. Distribution revenue increased for the six months ended June 30, 2021 compared to the same period in 2020 due to customer growth.

Transmission Revenues 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 increased for the three and six months ended June 30, 2021, compared to the same period in 2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilities.

Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.

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, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.

See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

The decrease $5 million for both the three and six months ended June 30, 2021 compared to the same period in 2020, 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, 2021		Six Months Ended June 30, 2021
	(Decrease) Increase		(Decrease) Increase
Credit loss expense	$	(7)	$	(5)
Labor, other benefits, contracting and materials	(5)		(12)
Pension and non-pension postretirement benefits expense	(1)		(2)
BSC and PHISCO costs	(1)		—



Other	7		8
	(7)		(11)

Regulatory required programs	1		1
Total decrease	$	(6)	$	(10)

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


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	4	$	8
Regulatory asset amortization	(6)		(5)
Regulatory required programs	6		10
Total increase	$	4	$	13

_________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were (4.2)% and (72.7)% for the three months ended June 30, 2021 and 2020, respectively, and 2.2% and (21.1)% for the six months ended June 30, 2021 and 2020, respectively. The change is primarily due to the April 24, 2020 settlement agreement of ongoing transmission related income tax regulatory liabilities. Note 3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement, and Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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DPL

Results of Operations — DPL


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	298	$	267	$	31	$	680	$	617	$	63
Operating expenses
Purchased power and fuel expense	108		107		(1)		263		249		(14)
Operating and maintenance	80		92		12		164		172		8
Depreciation and amortization	51		47		(4)		104		94		(10)
Taxes other than income taxes	16		17		1		33		32		(1)
Total operating expenses	255		263		8		564		547		(17)

Operating income	43		4		39		116		70		46
Other income and (deductions)
Interest expense, net	(16)		(15)		(1)		(30)		(31)		1
Other, net	4		2		2		6		5		1
Total other income and (deductions)	(12)		(13)		1		(24)		(26)		2
Income (loss) before income taxes	31		(9)		40		92		44		48
Income taxes	1		(28)		(29)		6		(20)		(26)
Net income	$	30	$	19	$	11	$	86	$	64	$	22

Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020. Net income increased $11 million primarily due to higher electric distribution rates and a decrease in credit loss expense.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020. Net income increased $22 million primarily due to higher electric distribution rates, favorable weather conditions at DPL's Delaware electric and natural gas service territories, and a decrease in credit loss expense.

The changes in Operating revenues consisted of the following:


	Three Months Ended June 30, 2021						Six Months Ended June 30, 2021
	(Decrease) Increase						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	—	$	(3)	$	(3)	$	4	$	2	$	6
Volume	2		(2)		—		2		(2)		—
Distribution	4		1		5		9		1		10
Transmission	28		—		28		28		—		28
Other	—		—		—		1		—		1
	34		(4)		30		44		1		45
Regulatory required programs	4		(3)		1		18		—		18
Total increase (decrease)	$	38	$	(7)	$	31	$	62	$	1	$	63

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces

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demand. During the three months ended June 30, 2021 compared to the same period in 2020, Operating revenues related to weather decreased due to the impact of unfavorable weather conditions in DPL's Delaware natural gas service territory. During the six months ended June 30, 2021 compared to the same period in 2020, Operating revenues related to weather increased due to the impact of favorable weather conditions in DPL's Delaware electric and natural gas service territories.

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, 2021 compared to same period in 2020 and normal weather consisted of the following:


Delaware Electric Service Territory				% Change
Three Months Ended June 30,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	480	606	471	(20.8)	%	1.9	%
Cooling Degree-Days	361	299	334	20.7	%	8.1	%

				% Change
Six Months Ended June 30,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	2,838	2,609	2,964	8.8	%	(4.3)	%
Cooling Degree-Days	364	299	334	21.7	%	9.0	%


Delaware Natural Gas Service Territory				% Change
Three Months Ended June 30,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	480	606	490	(20.8)	%	(2.0)	%

				% Change
Six Months Ended June 30,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	2,838	2,609	2,987	8.8	%	(5.0)	%

Volume, exclusive of the effects of weather, remained relatively consistent for the three and six months ended June 30, 2021 compared to the same period in 2020.


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)
	2021	2020					2021	2020
Residential	703	703	—	%	0.6	%	1,557	1,446	7.7	%	2.8	%
Small commercial & industrial	357	274	30.3	%	30.5	%	699	570	22.6	%	19.8	%
Large commercial & industrial	810	810	—	%	(0.3)	%	1,499	1,633	(8.2)	%	(8.9)	%
Public authorities & electric railroads	10	9	11.1	%	6.8	%	19	17	11.8	%	7.2	%
Total electric retail deliveries(a)	1,880	1,796	4.7	%	4.8	%	3,774	3,666	2.9	%	0.4	%


	As of June 30,
Number of Total Electric Customers (Maryland and Delaware)	2021	2020
Residential	475,061	470,788
Small commercial & industrial	62,880	61,958
Large commercial & industrial	1,213	1,402
Public authorities & electric railroads	607	612
Total	539,761	534,760

_________

(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.

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(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)
	2021	2020					2021	2020
Residential	713	1,168	(39.0)	%	(23.5)	%	5,107	4,815	6.1	%	(2.0)	%
Small commercial & industrial	430	557	(22.8)	%	(6.2)	%	2,295	2,228	3.0	%	(4.3)	%
Large commercial & industrial	393	411	(4.4)	%	(4.3)	%	853	863	(1.2)	%	(1.5)	%
Transportation	1,470	1,472	(0.1)	%	3.4	%	3,694	3,580	3.2	%	0.7	%
Total natural gas deliveries(a)	3,006	3,608	(16.7)	%	(6.8)	%	11,949	11,486	4.0	%	(1.6)	%


	As of June 30,
Number of Delaware Natural Gas Customers	2021	2020
Residential	127,503	126,245
Small commercial & industrial	9,953	9,914
Large commercial & industrial	18	17
Transportation	158	159
Total	137,632	136,335

__________

(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.

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

Distribution Revenue increased for the three and six months ended June 30, 2021 compared to the same period in 2020 primarily due to higher electric distribution rates in Maryland that became effective in July 2020 and higher electric and natural gas distribution rates in Delaware that became effective in the second half of 2020.

Transmission Revenues. 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 increased for the three and six months ended June 30, 2021, compared to the same period in 2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilities.

Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.

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 as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore DPL does not record Operating revenues or Purchased power and fuel expense related to the electricity. For customers that choose to purchase electric generation from DPL, DPL is permitted to recover the electricity and REC procurement costs from customers with a slight mark-up and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers natural gas costs without mark-up and records the amount in Operating revenues and Purchased power and fuel expense.

See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

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The increase of $1 million and $14 million for the three and six months ended June 30, 2021, compared to the same period in 2020, 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, 2021		Six Months Ended June 30, 2021
	(Decrease) Increase		(Decrease) Increase
Credit loss expense	$	(6)	$	(5)
Labor, other benefits, contracting and materials	(5)		(3)
Storm-related costs	(3)		(4)
Pension and non-pension postretirement benefits expense	(1)		(1)
BSC and PHISCO costs	1		3
Other	3		3
	(11)		(7)
Regulatory required programs	(1)		(1)
Total decrease	$	(12)	$	(8)

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


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	Increase		Increase
Depreciation and amortization(a)	$	3	$	7

Regulatory required programs	1		3
Total increase	$	4	$	10

_________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were 3.2% and 311.1% for the three months ended June 30, 2021 and 2020, respectively, and 6.5% and (45.5)% for the six months ended June 30, 2021 and 2020, respectively. The change is primarily due to the April 24, 2020 settlement agreement of ongoing transmission related income tax regulatory liabilities. Note 3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement, and Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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ACE

Results of Operations — ACE


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	319	$	256	$	63	$	629	$	532	$	97


Operating expenses
Purchased power expense	154		130		(24)		311		259		(52)
Operating and maintenance	73		82		9		150		160		10
Depreciation and amortization	40		44		4		87		86		(1)
Taxes other than income taxes	2		2		—		4		4		—
Total operating expenses	269		258		(11)		552		509		(43)
Gain on sale of assets	—		—		—		—		2		(2)
Operating income (loss)	50		(2)		52		77		25		52
Other income and (deductions)
Interest expense, net	(14)		(15)		1		(29)		(29)		—
Other, net	—		2		(2)		2		3		(1)
Total other income and (deductions)	(14)		(13)		(1)		(27)		(26)		(1)
Income (loss) before income taxes	36		(15)		51		50		(1)		51
Income taxes	(1)		(33)		(32)		(1)		(32)		(31)
Net income	$	37	$	18	$	19	$	51	$	31	$	20

Three Months Ended June 30, 2021 Compared to Three Months Ended June 30, 2020. Net income increased $19 million primarily due to higher transmission revenues due to an increase in capital investments and higher distribution revenues due to an increase in volume in ACE's service territory.

Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020. Net income increased $20 million primarily due to favorable weather conditions, higher transmission revenues due to an increase in capital investments and higher distribution revenues due to an increase in volume in ACE's service territory.

The changes in Operating revenues consisted of the following:


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	(Decrease) Increase		Increase (Decrease)
Weather	$	(1)	$	4
Volume	14		15
Distribution	—		(1)
Transmission	36		36
Other	(1)		—
	48		54




Regulatory required programs	15		43
Total increase	$	63	$	97

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. During the three months ended June 30, 2021 compared to the same period in 2020, Operating revenues related to weather remained relatively consistent. During the six months ended June 30, 2021 compared to the same period in 2020, Operating revenues related to weather increased due to the impact of favorable weather conditions in ACE's service territory.

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Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the three and six months ended June 30, 2021 compared to same period in 2020 and normal weather consisted of the following:


Heating and Cooling Degree-Days			Normal	% Change
Three Months Ended June 30,	2021	2020		2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	525	613	540	(14.4)	%	(2.8)	%
Cooling Degree-Days	321	312	305	2.9	%	5.2	%

			Normal	% Change
Six Months Ended June 30,	2021	2020		2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	2,873	2,561	3,008	12.2	%	(4.5)	%
Cooling Degree-Days	325	312	305	4.2	%	6.6	%

Volume, exclusive of the effects of weather, increased for the three and six months ended June 30, 2021 compared to the same period in 2020, primarily due to customer growth and usage.


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)
	2021	2020					2021	2020
Residential	975	850	14.7	%	16.2	%	1,903	1,660	14.6	%	11.3	%
Small commercial & industrial	333	276	20.7	%	22.3	%	638	570	11.9	%	9.9	%
Large commercial & industrial	761	702	8.4	%	8.8	%	1,477	1,437	2.8	%	2.4	%
Public authorities & electric railroads	11	11	—	%	2.0	%	24	24	—	%	1.4	%
Total electric retail deliveries(a)	2,080	1,839	13.1	%	14.2	%	4,042	3,691	9.5	%	7.6	%


	As of June 30,
Number of Electric Customers	2021	2020
Residential	499,436	496,668
Small commercial & industrial	61,836	61,468
Large commercial & industrial	3,243	3,327
Public authorities & electric railroads	707	687
Total	565,222	562,150

_________

(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 remained relatively consistent for the three and six months ended June 30, 2021 compared to the same period in 2020.

Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.

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ACE

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 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, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.

The increase of $24 million and $52 million for the three and six months ended June 30, 2021 compared to the same period in 2020, 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, 2021		Six Months Ended June 30, 2021
	(Decrease) Increase		(Decrease) Increase
Labor, other benefits, contracting and materials	$	(4)	$	(3)
Storm-related costs	(3)		(3)
Pension and non-pension postretirement benefits expense	—		(1)

BSC and PHISCO costs	—		1
Other	—		2
	(7)		(4)

Regulatory required programs(a)	(2)		(6)
Total decrease	$	(9)	$	(10)

_________

(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 the Societal Benefits Charge.

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


	Three Months Ended June 30, 2021		Six Months Ended June 30, 2021
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	4	$	7
Regulatory asset amortization	(1)		(1)
Regulatory required programs	(7)		(5)
Total (decrease) increase	$	(4)	$	1

_________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were (2.8)% and 220.0% for the three months ended June 30, 2021 and 2020, respectively, and (2.0)% and 3200.0% for the six months ended June 30, 2021 and 2020, respectively. The change is primarily due to the April 24, 2020 settlement agreement of ongoing transmission related income tax regulatory liabilities. Note 3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement, and Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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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 $10.5 billion. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements.

The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB 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 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

NRC Minimum Funding Requirements (Exelon and Generation)

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are typically 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 8 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT funds could appreciate in value. A shortfall could require that Generation address the shortfall by providing additional financial assurances such as surety bonds, letters of credit, or parent company guarantees for Generation’s share of the funding assurance. However, the amount of any assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. No later than two years after shutting down a plant, Generation must submit a PSDAR to the NRC that includes the planned option for decommissioning the site. Upon early retirement, Dresden will have adequate funding assurance, however, due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value, Byron may no longer meet the NRC minimum funding requirements and, as a result, additional financial assurance may be required. Based on the decommissioning approach selected by Generation in the July 28, 2021 PSDAR filing for the Byron units, financial assurance for radiological decommissioning at Byron of up to $60 million could be required.

Upon issuance of any required financial assurance, 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, under the regulations, the NRC must approve an exemption in order for Generation to utilize the NDT funds to pay for non-radiological decommissioning costs (i.e. spent fuel management and site restoration

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costs, if applicable). If a unit does not receive this exemption, those costs would be borne by Generation without reimbursement from or access to the NDT funds. Based on current projections of the decommissioning approaches selected and expected exemptions from the NRC, it is expected that Dresden would not require supplemental cash from Generation, but some portion of the Byron spent fuel management costs would need to be funded through supplemental cash from Generation. While the ultimate amounts may vary and could be offset by reimbursement of certain spent fuel management costs under the DOE settlement agreement, decommissioning for Byron may require supplemental cash from Generation of up to $135 million, net of taxes, over a period of 10 years after permanent shutdown.

As of June 30, 2021, Generation is not required to provide any additional financial assurances 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 to allow the TMI Unit 1 NDT funds to be used for site restoration costs was submitted to the NRC on May 20, 2021 and is pending NRC review.

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. Refer to Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on credit facilities and nonrecourse debt.

Cash Flows from Operating Activities (All Registrants)

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 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2020 Form 10-K for additional information on 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, 2021 and 2020 by Registrant:


(Decrease) increase in cash flows from operating activities	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income	$	(739)	$	(1,124)	$	283	$	93	$	35	$	67	$	25	$	22	$	20
Adjustments to reconcile net income to cash:
Non-cash operating activities	(326)		164		(219)		(15)		(12)		(54)		(9)		(19)		(19)
Pension and non-pension postretirement benefit contributions	(1)		31		(29)		3		(3)		(9)		(1)		—		(1)
Income taxes	304		(27)		56		9		(53)		29		(2)		26		—
Changes in working capital and other noncurrent assets and liabilities	(1,501)		(1,399)		(36)		(109)		(85)		(3)		(33)		11		12
Option premiums received (paid), net	104		104		—		—		—		—		—		—		—
Collateral received, net	617		613		5		—		2		—		—		—		—
(Decrease) increase in cash flows from operating activities	$	(1,542)	$	(1,638)	$	60	$	(19)	$	(116)	$	30	$	(20)	$	40	$	12

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, 2021 and 2020 were as follows:

•See Note 18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.

•See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.

•Changes in working capital and other noncurrent assets and liabilities are primarily due to impacts resulting from the sale of customer accounts receivable at Exelon and Generation. See Note 6 – Accounts Receivable for additional information.

•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 over-the-counter markets.

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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, 2021 and 2020 by Registrant:


Increase (decrease) in cash flows from investing activities	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	(267)	$	211	$	(133)	$	(65)	$	(72)	$	(203)	$	(115)	$	(27)	$	(61)
Proceeds from NDT fund sales, net	(48)		(48)		—		—		—		—		—		—		—

Proceeds from sales of assets and businesses	724		724		—		—		—		—		—		—		—
Changes in intercompany money pool	—		—		—		(68)		—		—		—		46		—
Collection of DPP	1,107		1,107		—		—		—		—		—		—		—

Other investing activities	13		(14)		16		1		14		(4)		1		4		(5)
Increase (decrease) in cash flows from investing activities	$	1,529	$	1,980	$	(117)	$	(132)	$	(58)	$	(207)	$	(114)	$	23	$	(66)

Significant investing cash flow impacts for the Registrants for six months ended June 30, 2021 and 2020 were as follows:

•Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer to Liquidity and Capital Resources of the Exelon 2020 Form 10-K for additional information on projected capital expenditure spending.

•See Note 2 – Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information related to the sale of a significant portion of Generation's solar business.

•Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

•See Note 6 – Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the Collection of DPP.

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Capital Expenditure Spending

As of June 30, 2021, there have been no material changes to the Registrants' projected capital expenditures as disclosed in Liquidity and Capital Resources of the Exelon 2020 Form 10-K.

Cash Flows from Financing Activities (All Registrants)

The following table provides a summary of the change in cash flows from financing activities for the six months ended June 30, 2021 and 2020 by Registrant:


(Decrease) increase in cash flows from financing activities	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	85	$	(620)	$	(160)	$	—	$	76	$	153	$	187	$	(90)	$	56
Long-term debt, net	(807)		628		(300)		25		200		38		1		26		12
Changes in intercompany money pool	—		(285)		—		(40)		—		(22)		(41)		—		(5)

Dividends paid on common stock	(1)		—		(4)		1		(23)		—		(22)		3		(194)
Distributions to member	—		21		—		—		—		(146)		—		—		—
Contributions from parent/member	—		—		146		164		(26)		201		1		14		187

Other financing activities	21		1		3		(1)		2		—		4		(2)		(3)
(Decrease) increase in cash flows from financing activities	$	(702)	$	(255)	$	(315)	$	149	$	229	$	224	$	130	$	(49)	$	53

Significant financing cash flow impacts for the Registrants for the six months ended June 30, 2021 and 2020 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 13 — Debt and Credit Agreements of the Combined Notes to 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 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to debt redemptions tables below for additional information.

•Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

•Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2020 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.

•For the six months ended June 30, 2021, other financing activities primarily consists of debt issuance costs. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.

Debt

See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

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During the six months ended June 30, 2021, the following long-term debt was retired and/or redeemed:


Company	Type	Interest Rate			Maturity	Amount
Exelon	Senior Notes	2.45	%		April 15, 2021	$	300
Exelon	Long-Term Software License Agreement	3.95	%		May 1, 2024	24
Exelon	Long-Term Software License Agreements	3.62	%		December 1, 2025	1


Generation	Continental Wind Nonrecourse Debt(a)	6.00	%		February 28, 2033	19
Generation	EGR IV Nonrecourse Debt(a)	3 month LIBOR + 2.50 %		(b)	December 15, 2027	17
Generation	SolGen Nonrecourse Debt(a)	3.93	%		September 30, 2036	7
Generation	Antelope Valley DOE Nonrecourse Debt(a)	2.29 % - 3.56 %			January 5, 2037	7

Generation	West Medway II Nonrecourse Debt(a)	LIBOR + 3%		(c)	March 31, 2026	3
Generation	RPG Nonrecourse Debt(a)	4.11	%		March 31, 2035	3






ACE	First Mortgage Bonds	4.35	%		April 1, 2021	200
ACE	Tax-Exempt First Mortgage Bonds	6.80	%		March 1, 2021	39
ACE	Transition Bonds	5.55	%		October 20, 2021	10

_________

(a)See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on nonrecourse debt.

(b)The interest rate was amended to 3 month LIBOR + 2.50 % on June 16, 2021.

(c)The nonrecourse debt has an average blended interest rate.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the six months ended June 30, 2021 and for the third quarter of 2021 were as follows:

Period

Declaration Date

Shareholder of Record Date

Dividend Payable Date

Cash per Share(a)

First Quarter 2021

February 21, 2021

March 8, 2021

March 15, 2021

0.3825

Second Quarter 2021

April 27, 2021

May 14, 2021

June 10, 2021

0.3825

Third Quarter 2021

July 27, 2021

August 13, 2021

September 10, 2021

0.3825

_________

(a)Exelon's Board of Directors approved an updated dividend policy for 2021. The 2021 quarterly dividend will remain the same as the 2020 dividend of $0.3825 per share.

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 $10.5 billion in aggregate total commitments of which $8.0 billion was available to support additional commercial paper as of June 30, 2021, 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 six months ended June 30, 2021 to fund their short-term liquidity needs, when necessary. Generation used its available credit facilities to manage short-term liquidity needs as a result of the impacts of the February 2021 extreme cold weather event and continues to believe it has sufficient cash on hand and available capacity on its revolver to meet its liquidity requirements. 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 2020 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, 2021, it would have been required to provide incremental collateral of approximately $1.9 billion to meet collateral

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obligations for derivatives, non-derivatives, normal purchases and normal sales contracts, and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within the $4.7 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, 2021 and available credit facility capacity prior to any incremental collateral at June 30, 2021:


	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral

ComEd	$	27	$	—	$	965
PECO	1		22		600
BGE	4		40		600

Pepco	3		—		146
DPL	4		12		300
ACE	1		—		122

_________

(a)Represents incremental collateral related to natural gas procurement contracts.

Exelon Credit Facilities

See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ short-term borrowing activity. See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on the Registrants’ credit facilities.

Security Ratings

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.

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 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for Exelon Corporate and the Utility Registrants did not change for the six months ended June 30, 2021. On February 24, 2021, S&P lowered Generation's senior unsecured debt rating to 'BBB-' from 'BBB'.

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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, 2021, are presented in the following table. ACE had no activity within the PHI Intercompany Money Pool for the three months ended June 30, 2021.


	During the Three Months Ended June 30, 2021				As of June 30, 2021
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	469	$	—	$	276
Generation	—		(230)		—
PECO	303		—		—
BSC	—		(435)		(322)
PHI Corporate	—		(27)		(9)
PCI	55		—		55



	During the Three Months Ended June 30, 2021				As of June 30, 2021
PHI Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)

Pepco	$	—	$	(30)	$	(9)
DPL	30		—		9

Shelf Registration Statements

Exelon, Generation, and the Utility Registrants 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.

Regulatory Authorizations

The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

As of June 30, 2021

Short-term Financing Authority(a)

Remaining Long-term Financing Authority(a)

Commission

Expiration Date

Amount

Commission

Expiration Date

Amount

ComEd(b)

FERC

December 31, 2021

2,500

ICC

2023 & 2024

543

PECO

FERC

December 31, 2021

1,500

PAPUC

December 31, 2021

850

BGE

FERC

December 31, 2021

700

MDPSC

N/A

500

Pepco

FERC

December 31, 2021

500

MDPSC / DCPSC

December 31, 2022

750

DPL

FERC

December 31, 2021

500

MDPSC / DPSC

December 31, 2022

172

ACE

NJBPU

December 31, 2021

350

NJBPU

December 31, 2022

250

_________

(a)Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.

(b)ComEd had $350 million available in long-term debt refinancing authority and $193 million available in new money long-term debt financing authority from the ICC as of June 30, 2021 and has an expiration date of February 1, 2024 and February 1, 2023, respectively. On June 29, 2021, ComEd filed an application for $2 billion in new money long-term debt financing authority from the ICC and expects approval by December 31, 2021.

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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 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

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 2020 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 2020 Form 10-K and Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE 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 2020 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 2021 through 2023.

As of June 30, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 98%-101% for 2021. 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, 2021 market conditions and hedged position would be an increase in pre-tax net income of approximately $39 million for 2021. See Note 12 — 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 2021 through 2025 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 2020 Annual Report on Form 10-K. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding commodity price risk exposure.

Trading and Non-Trading Marketing Activities

The following table detailing Exelon’s, Generation’s, and ComEd’s trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

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The following table provides detail on changes in Exelon’s, Generation’s, and ComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, 2020 to June 30, 2021. 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 12 — 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, 2021 and December 31, 2020.


	Exelon		Generation		ComEd
Total mark-to-market energy contract net assets (liabilities) at December 31, 2020(a)	$	428	$	729	$	(301)
Total change in fair value during 2021 of contracts recorded in results of operations	541		541		—
Reclassification to realized at settlement of contracts recorded in results of operations	(47)		(47)		—

Changes in fair value — recorded through regulatory assets(b)	36		—		36
Changes in allocated collateral	(968)		(968)		—
Net option premium paid	(2)		(2)		—
Option premium amortization	(20)		(20)		—
Upfront payments and amortizations(c)	(48)		(48)		—
Total mark-to-market energy contract net assets (liabilities) at June 30, 2021(a)	$	(80)	$	185	$	(265)

_________

(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, 2021, ComEd recorded a regulatory asset of $265 million related to its mark-to-market derivative liabilities with unaffiliated suppliers. For the six months ended June 30, 2021, ComEd recorded $23 million of increases 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.

(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 14 — 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
	2021		2022		2023		2024		2025		2026 and Beyond
Normal Operations, Commodity derivative contracts(a)(b):
Actively quoted prices (Level 1)	$	122	$	135	$	37	$	28	$	25	$	20	$	367
Prices provided by external sources (Level 2)	7		224		52		(1)		1		—		283
Prices based on model or other valuation methods (Level 3)(c)	(107)		(395)		13		(30)		(15)		(196)		(730)
Total	$	22	$	(36)	$	102	$	(3)	$	11	$	(176)	$	(80)

_________

(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/(received) from counterparties (and offset against mark-to-market assets and liabilities) of $(552) million at June 30, 2021.

(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
	2021		2022		2023		2024		2025		2026 and Beyond
Normal Operations, Commodity derivative contracts(a)(b):
Actively quoted prices (Level 1)	$	122	$	135	$	37	$	28	$	25	$	20	$	367
Prices provided by external sources (Level 2)	7		224		52		(1)		1		—		283
Prices based on model or other valuation methods (Level 3)	(96)		(371)		39		(4)		10		(43)		(465)
Total	$	33	$	(12)	$	128	$	23	$	36	$	(23)	$	185

_________

(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/(received) from counterparties (and offset against mark-to-market assets and liabilities) of $(552) million at June 30, 2021.

ComEd


	Maturities Within												Total Fair Value
	2021		2022		2023		2024		2025		2026 and Beyond
Commodity derivative contracts(a):
Prices based on model or other valuation methods (Level 3)(a)	$	(11)	$	(24)	$	(26)	$	(26)	$	(25)	$	(153)	$	(265)

_________

(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 fair value of contracts at the reporting date. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for detailed discussion of credit risk.

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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, 2021. 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 amounts 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, 2021	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	$	446	$	56	$	390	—	$	—
Non-investment grade	15		1		14
No external ratings
Internally rated — investment grade	134		1		133
Internally rated — non-investment grade	126		35		91
Total	$	721	$	93	$	628	—	$	—


	Maturity of Credit Risk Exposure
Rating as of June 30, 2021	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	345	$	48	$	53	$	446
Non-investment grade	15		—		—		15
No external ratings
Internally rated — investment grade	110		17		7		134
Internally rated — non-investment grade	88		28		10		126
Total	$	558	$	93	$	70	$	721


Net Credit Exposure by Type of Counterparty	As of June 30, 2021
Financial institutions	$	27
Investor-owned utilities, marketers, power producers	448
Energy cooperatives and municipalities	85
Other	68
Total	$	628

_________

(a)As of June 30, 2021, credit collateral held from counterparties where Generation had credit exposure included $53 million of cash and $40 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 2020 Annual Report on Form 10-K. See Note 12 — 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)

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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 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. See Note 15 — 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 17 — Debt and Credit Agreements of Exelon’s 2020 Annual Report on Form 10-K for additional information.

Utility Registrants

As of June 30, 2021, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Exelon and Generation use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon and Generation may also utilize interest rate swaps to manage their interest rate exposure. A hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $1 million decrease in Exelon pre-tax income for the six months ended June 30, 2021. 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 12 — 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, 2021, 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 $886 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.

ITEM 4. CONTROLS AND PROCEDURES

During the second quarter of 2021, 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

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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, 2021, 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 2021 that materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s 2020 Form 10-K and (b) Notes 3 — Regulatory Matters and 15 — 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 All Registrants

At June 30, 2021, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2020 Form 10-K in ITEM 1A. RISK FACTORS.

ITEM 4. MINE SAFETY DISCLOSURES

All Registrants

Not applicable to the Registrants.

ITEM 5. OTHER INFORMATION

All Registrants

None.

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ITEM 6. EXHIBITS

Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis and the relevant Registrant agrees to furnish a copy of any such instrument to the Commission upon request.


Exhibit No.			Description

4.1			BGE Form of 2.250% notes due June 15, 2031 (File 001-01910, Form 8-K dated June 10, 2021, Exhibit 4.2)

10.1			Amendment Number One to the Exelon Corporation Senior Management 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.

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

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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2021 filed by the following officers for the following companies:


Exhibit No.			Description
31-1			Filed by Christopher M. Crane for Exelon Corporation

31-2			Filed by Joseph Nigro for Exelon Corporation

31-3			Filed by Christopher M. Crane 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, 2021 filed by the following officers for the following companies:


Exhibit No.			Description
32-1			Filed by Christopher M. Crane for Exelon Corporation

32-2			Filed by Joseph Nigro for Exelon Corporation

32-3			Filed by Christopher M. Crane 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

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SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON CORPORATION


/s/ CHRISTOPHER M. CRANE						/s/ JOSEPH NIGRO
Christopher M. Crane						Joseph Nigro
President, 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, 2021

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON GENERATION COMPANY, LLC


/s/ CHRISTOPHER M. CRANE						/s/ BRYAN P. WRIGHT
Christopher M. Crane						Bryan P. Wright
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, 2021

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

COMMONWEALTH EDISON COMPANY


/s/ JOSEPH DOMINGUEZ						/s/ JEANNE M. JONES
Joseph Dominguez						Jeanne M. Jones
Chief Executive Officer (Principal Executive Officer)						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ STEVEN J. CICHOCKI
Steven J. Cichocki
Director, Accounting (Principal Accounting Officer)

August 4, 2021

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PECO ENERGY COMPANY


/s/ MICHAEL A. INNOCENZO						/s/ ROBERT J. STEFANI
Michael A. Innocenzo						Robert J. Stefani
President and Chief Executive Officer (Principal Executive Officer)						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ CAROLINE FULGINITI
Caroline Fulginiti
Director, Accounting (Principal Accounting Officer)

August 4, 2021

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BALTIMORE GAS AND ELECTRIC COMPANY


/s/ CARIM V. KHOUZAMI						/s/ DAVID M. VAHOS
Carim V. Khouzami						David M. Vahos
Chief Executive Officer (Principal Executive Officer)						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ JASON T. JONES
Jason T. Jones
Director, Accounting (Principal Accounting Officer)

August 4, 2021

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PEPCO HOLDINGS LLC


/s/ DAVID M. VELAZQUEZ						/s/ PHILLIP S. BARNETT
David M. Velazquez						Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting (Principal Accounting Officer)

August 4, 2021

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

POTOMAC ELECTRIC POWER COMPANY


/s/ DAVID M. VELAZQUEZ						/s/ PHILLIP S. BARNETT
David M. Velazquez						Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting (Principal Accounting Officer)

August 4, 2021

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DELMARVA POWER & LIGHT COMPANY


/s/ DAVID M. VELAZQUEZ						/s/ PHILLIP S. BARNETT
David M. Velazquez						Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting (Principal Accounting Officer)

August 4, 2021

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

ATLANTIC CITY ELECTRIC COMPANY


/s/ DAVID M. VELAZQUEZ						/s/ PHILLIP S. BARNETT
David M. Velazquez						Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting (Principal Accounting Officer)

August 4, 2021

211