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 March 31, 2021

or

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

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

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

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

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

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

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

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

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

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

The number of shares outstanding of each registrant’s common stock as of March 31, 2021 was:

Exelon Corporation Common Stock, without par value	977,175,235
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	15
	Consolidated Statements of Cash Flows	16
	Consolidated Balance Sheets	17
	Consolidated Statements of Changes in Equity	19
	Commonwealth Edison Company
	Consolidated Statements of Operations and Comprehensive Income	20
	Consolidated Statements of Cash Flows	21
	Consolidated Balance Sheets	22
	Consolidated Statements of Changes in Shareholders' Equity	24
	PECO Energy Company
	Consolidated Statements of Operations and Comprehensive Income	25
	Consolidated Statements of Cash Flows	26
	Consolidated Balance Sheets	27
	Consolidated Statements of Changes in Shareholder's Equity	29
	Baltimore Gas and Electric Company
	Statements of Operations and Comprehensive Income	30
	Statements of Cash Flows	31
	Balance Sheets	32
	Statements of Changes in Shareholder's Equity	34
	Pepco Holdings LLC
	Consolidated Statements of Operations and Comprehensive Income	35
	Consolidated Statements of Cash Flows	36
	Consolidated Balance Sheets	37
	Consolidated Statements of Changes in Equity	39

1

	Page No.
Potomac Electric Power Company
Statements of Operations and Comprehensive Income	40
Statements of Cash Flows	41
Balance Sheets	42
Statements of Changes in Shareholder's Equity	44
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income	45
Statements of Cash Flows	46
Balance Sheets	47
Statements of Changes in Shareholder’s Equity	49
Atlantic City Electric Company
Consolidated Statements of Operations and Comprehensive Income	50
Consolidated Statements of Cash Flows	51
Consolidated Balance Sheets	52
Consolidated Statements of Changes in Shareholder’s Equity	54
Combined Notes to Consolidated Financial Statements
1. Significant Accounting Policies	55
2. Mergers, Acquisitions and Dispositions	56
3. Regulatory Matters	57
4. Revenue from Contracts with Customers	62
5. Segment Information	64
6. Accounts Receivable	72
7. Early Plant Retirements	75
8. Nuclear Decommissioning	77
9. Income Taxes	79
10. Retirement Benefits	80
11. Derivative Financial Instruments	82
12. Debt and Credit Agreements	87
13. Fair Value of Financial Assets and Liabilities	90
14. Commitments and Contingencies	100
15. Changes in Accumulated Other Comprehensive Income	107
16. Variable Interest Entities	108
17. Supplemental Financial Information	112
18. Related Party Transactions	117
19. Planned Separation	120

2

		Page No.
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	121
	Exelon Corporation	121
	Executive Overview	121
	Financial Results of Operations	121
	Significant 2021 Transactions and Developments	124
	Other Key Business Drivers and Management Strategies	126
	Critical Accounting Policies and Estimates	127
	Results of Operations By Registrant	127
	Exelon Generation Company, LLC	128
	Commonwealth Edison Company	134
	PECO Energy Company	137
	Baltimore Gas and Electric Company	141
	Pepco Holdings LLC	144
	Potomac Electric Power Company	145
	Delmarva Power & Light Company	147
	Atlantic City Electric Company	151
	Liquidity and Capital Resources	154
	Contractual Obligations and Off-Balance Sheet Arrangements	161
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	162
ITEM 4.	CONTROLS AND PROCEDURES	166
PART II.	OTHER INFORMATION	167
ITEM 1.	LEGAL PROCEEDINGS	167
ITEM 1A.	RISK FACTORS	167
ITEM 4.	MINE SAFETY DISCLOSURES	167
ITEM 5.	OTHER INFORMATION	167
ITEM 6.	EXHIBITS	168
SIGNATURES		171
	Exelon Corporation	171
	Exelon Generation Company, LLC	172
	Commonwealth Edison Company	173
	PECO Energy Company	174
	Baltimore Gas and Electric Company	175
	Pepco Holdings LLC	176
	Potomac Electric Power Company	177
	Delmarva Power & Light Company	178
	Atlantic City Electric Company	179

3

GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon	Exelon Corporation
Generation	Exelon Generation Company, LLC
ComEd	Commonwealth Edison Company
PECO	PECO Energy Company
BGE	Baltimore Gas and Electric Company
Pepco Holdings or PHI	Pepco Holdings LLC
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

4

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
FASB	Financial Accounting Standards Board
FEJA	Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC	Federal Energy Regulatory Commission
FRCC	Florida Reliability Coordinating Council
FRR	Fixed Resource Requirement
GAAP	Generally Accepted Accounting Principles in the United States
GCR	Gas Cost Rate
GSA	Generation Supply Adjustment
IBEW	International Brotherhood of Electrical Workers
ICC	Illinois Commerce Commission
ICE	Intercontinental Exchange
IPA	Illinois Power Agency
IRC	Internal Revenue Code
IRS	Internal Revenue Service
ISO	Independent System Operator
ISO-NE	Independent System Operator New England Inc.

5

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
NRC	Nuclear Regulatory Commission
NYISO	New York Independent System Operator Inc.
NYMEX	New York Mercantile Exchange
NYPSC	New York Public Service Commission
OCI	Other Comprehensive Income
OIESO	Ontario Independent Electricity System Operator
OPEB	Other Postretirement Employee Benefits
PAPUC	Pennsylvania Public Utility Commission
PGC	Purchased Gas Cost Clause
PG&E	Pacific Gas and Electric Company
PJM	PJM Interconnection, LLC
POLR	Provider of Last Resort
PPA	Power Purchase Agreement
PPE	Property, plant, and equipment
Price-Anderson Act	Price-Anderson Nuclear Industries Indemnity Act of 1957
PRP	Potentially Responsible Parties
PSDAR	Post-Shutdown Decommissioning Activities Report
PSEG	Public Service Enterprise Group Incorporated
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

6

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
VIE	Variable Interest Entity
WECC	Western Electric Coordinating Council
ZEC	Zero Emission Credit, or Zero Emission Certificate
ZES	Zero Emission Standard

7

FILING FORMAT

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

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the 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 14, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.

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

WHERE TO FIND MORE INFORMATION

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

8

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

9

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
(In millions, except per share data)	2021		2020
Operating revenues
Competitive businesses revenues	$	5,265	$	4,404
Rate-regulated utility revenues	4,496		4,276
Revenues from alternative revenue programs	129		67
Total operating revenues	9,890		8,747
Operating expenses
Competitive businesses purchased power and fuel	4,610		2,710
Rate-regulated utility purchased power and fuel	1,358		1,157
Operating and maintenance	1,979		2,204
Depreciation and amortization	1,697		1,021
Taxes other than income taxes	438		437
Total operating expenses	10,082		7,529
Gain on sales of assets and businesses	71		2
Operating (loss) income	(121)		1,220
Other income and (deductions)
Interest expense, net	(380)		(404)
Interest expense to affiliates	(6)		(6)
Other, net	225		(725)
Total other income and (deductions)	(161)		(1,135)
(Loss) income before income taxes	(282)		85
Income taxes	(19)		(294)
Equity in losses of unconsolidated affiliates	(1)		(3)
Net (loss) income	(264)		376
Net income (loss) attributable to noncontrolling interests	25		(206)
Net (loss) income attributable to common shareholders	$	(289)	$	582
Comprehensive income, net of income taxes
Net (loss) income	$	(264)	$	376
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)
Actuarial loss reclassified to periodic benefit cost	56		47
Pension and non-pension postretirement benefit plan valuation adjustment	(2)		(7)
Unrealized loss on cash flow hedges	—		(1)
Unrealized gain (loss) on foreign currency translation	1		(8)
Other comprehensive income	54		21
Comprehensive (loss) income	(210)		397
Comprehensive income (loss) attributable to noncontrolling interests	25		(206)
Comprehensive (loss) income attributable to common shareholders	$	(235)	$	603
Average shares of common stock outstanding:
Basic	977		975
Assumed exercise and/or distributions of stock-based awards	—		1
Diluted(a)	977		976
(Losses) earnings per average common share
Basic	$	(0.30)	$	0.60
Diluted	$	(0.30)	$	0.60

__________

(a)The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was less than 1 million for the three months ended March 31, 2021 and March 31, 2020.

See the Combined Notes to Consolidated Financial Statements

10

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Cash flows from operating activities
Net (loss) income	$	(264)	$	376
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	2,104		1,378
Asset impairments	1		8
Gain on sales of assets and businesses	(71)		—
Deferred income taxes and amortization of investment tax credits	(142)		(245)
Net fair value changes related to derivatives	(178)		(132)
Net realized and unrealized (gains) losses on NDT funds	(118)		651
Unrealized loss on equity investments	23		—
Other non-cash operating activities	(170)		273
Changes in assets and liabilities:
Accounts receivable	(372)		800
Inventories	77		81
Accounts payable and accrued expenses	(176)		(976)
Option premiums received (paid), net	16		(38)
Collateral received (posted), net	273		(21)
Income taxes	113		(56)
Pension and non-pension postretirement benefit contributions	(537)		(531)
Other assets and liabilities	(1,840)		(488)
Net cash flows (used in) provided by operating activities	(1,261)		1,080
Cash flows from investing activities
Capital expenditures	(2,140)		(2,016)
Proceeds from NDT fund sales	2,908		1,183
Investment in NDT funds	(2,939)		(1,234)
Collection of DPP	1,574		—
Proceeds from sales of assets and businesses	680		—
Other investing activities	12		(8)
Net cash flows provided by (used in) investing activities	95		(2,075)
Cash flows from financing activities
Changes in short-term borrowings	597		109
Proceeds from short-term borrowings with maturities greater than 90 days	500		500
Issuance of long-term debt	1,705		2,652
Retirement of long-term debt	(79)		(1,032)
Dividends paid on common stock	(374)		(373)
Proceeds from employee stock plans	31		30
Other financing activities	(46)		(21)
Net cash flows provided by financing activities	2,334		1,865
Increase in cash, restricted cash, and cash equivalents	1,168		870
Cash, restricted cash, and cash equivalents at beginning of period	1,166		1,122
Cash, restricted cash, and cash equivalents at end of period	$	2,334	$	1,992
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(324)	$	(180)
Increase in DPP	1,339		—

See the Combined Notes to Consolidated Financial Statements

11

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	1,908	$	663
Restricted cash and cash equivalents	374		438
Accounts receivable
Customer accounts receivable	4,017		3,597
Customer allowance for credit losses	(442)		(366)
Customer accounts receivable, net	3,575		3,231
Other accounts receivable	1,320		1,469
Other allowance for credit losses	(79)		(71)
Other accounts receivable, net	1,241		1,398
Mark-to-market derivative assets	568		644
Unamortized energy contract assets	38		38
Inventories, net
Fossil fuel and emission allowances	205		297
Materials and supplies	1,427		1,425
Regulatory assets	1,269		1,228
Renewable energy credits	694		633
Assets held for sale	11		958
Other	1,687		1,609
Total current assets	12,997		12,562
Property, plant, and equipment (net of accumulated depreciation and amortization of $28,121 and $26,727 as of March 31, 2021 and December 31, 2020, respectively)	82,588		82,584
Deferred debits and other assets
Regulatory assets	8,810		8,759
Nuclear decommissioning trust funds	14,688		14,464
Investments	431		440
Goodwill	6,677		6,677
Mark-to-market derivative assets	491		555
Unamortized energy contract assets	285		294
Other	3,033		2,982
Total deferred debits and other assets	34,415		34,171
Total assets(a)	$	130,000	$	129,317

See the Combined Notes to Consolidated Financial Statements

12

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	3,128	$	2,031
Long-term debt due within one year	2,281		1,819
Accounts payable	3,430		3,562
Accrued expenses	1,729		2,078
Payables to affiliates	5		5
Regulatory liabilities	663		581
Mark-to-market derivative liabilities	422		295
Unamortized energy contract liabilities	98		100
Renewable energy credit obligation	645		661
Liabilities held for sale	3		375
Other	1,176		1,264
Total current liabilities	13,580		12,771
Long-term debt	36,248		35,093
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	13,129		13,035
Asset retirement obligations	12,405		12,300
Pension obligations	3,951		4,503
Non-pension postretirement benefit obligations	1,988		2,011
Spent nuclear fuel obligation	1,208		1,208
Regulatory liabilities	9,130		9,485
Mark-to-market derivative liabilities	453		473
Unamortized energy contract liabilities	217		238
Other	2,988		2,942
Total deferred credits and other liabilities	45,469		46,195
Total liabilities(a)	95,687		94,449
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 977 shares and 976 shares outstanding at March 31, 2021 and December 31, 2020, respectively)	19,412		19,373
Treasury stock, at cost (2 shares at March 31, 2021 and December 31, 2020)	(123)		(123)
Retained earnings	16,072		16,735
Accumulated other comprehensive loss, net	(3,346)		(3,400)
Total shareholders’ equity	32,015		32,585
Noncontrolling interests	2,298		2,283
Total equity	34,313		34,868
Total liabilities and shareholders’ equity	$	130,000	$	129,317

__________

(a)Exelon’s consolidated assets include $9,985 million and $10,200 million at March 31, 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 March 31, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 16 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

13

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Three Months Ended March 31, 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

	Three Months Ended March 31, 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

See the Combined Notes to Consolidated Financial Statements

14

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Operating revenues
Operating revenues	$	5,264	$	4,403
Operating revenues from affiliates	295		330
Total operating revenues	5,559		4,733
Operating expenses
Purchased power and fuel	4,610		2,710
Purchased power and fuel from affiliates	—		(6)
Operating and maintenance	856		1,121
Operating and maintenance from affiliates	145		142
Depreciation and amortization	940		304
Taxes other than income taxes	121		129
Total operating expenses	6,672		4,400
Gain on sales of assets and businesses	71		—
Operating (loss) income	(1,042)		333
Other income and (deductions)
Interest expense, net	(68)		(100)
Interest expense to affiliates	(4)		(9)
Other, net	167		(771)
Total other income and (deductions)	95		(880)
Loss before income taxes	(947)		(547)
Income taxes	(179)		(389)
Equity in losses of unconsolidated affiliates	(1)		(3)
Net loss	(769)		(161)
Net income (loss) attributable to noncontrolling interests	24		(206)
Net (loss) income attributable to membership interest	$	(793)	$	45
Comprehensive income, net of income taxes
Net loss	$	(769)	$	(161)
Other comprehensive income (loss), net of income taxes
Unrealized loss on cash flow hedges	—		(1)
Unrealized gain (loss) on foreign currency translation	1		(8)
Other comprehensive income (loss), net of income taxes	1		(9)
Comprehensive loss	(768)		(170)
Comprehensive income (loss) attributable to noncontrolling interests	24		(206)
Comprehensive (loss) income attributable to membership interest	$	(792)	$	36

See the Combined Notes to Consolidated Financial Statements

15

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Cash flows from operating activities
Net loss	$	(769)	$	(161)
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	1,346		661
Asset impairments	1		8
Gain on sales of assets and businesses	(71)		—
Deferred income taxes and amortization of investment tax credits	(123)		(329)
Net fair value changes related to derivatives	(178)		(127)
Net realized and unrealized (gains) losses on NDT funds	(118)		651
Unrealized loss on equity investments	23		—
Other non-cash operating activities	(202)		205
Changes in assets and liabilities:
Accounts receivable	(453)		787
Receivables from and payables to affiliates, net	59		34
Inventories	50		39
Accounts payable and accrued expenses	208		(614)
Option premiums received (paid), net	16		(38)
Collateral received (posted), net	270		(22)
Income taxes	(55)		(58)
Pension and non-pension postretirement benefit contributions	(205)		(232)
Other assets and liabilities	(1,411)		(184)
Net cash flows (used in) provided by operating activities	(1,612)		620
Cash flows from investing activities
Capital expenditures	(382)		(558)
Proceeds from NDT fund sales	2,908		1,183
Investment in NDT funds	(2,939)		(1,234)
Collection of DPP	1,574		—
Proceeds from sales of assets and businesses	680		—
Changes in Exelon intercompany money pool	—		(254)
Other investing activities	(2)		(8)
Net cash flows provided by (used in) investing activities	1,839		(871)
Cash flows from financing activities
Changes in short-term borrowings	997		275
Proceeds from short-term borrowings with maturities greater than 90 days	—		500
Issuance of long-term debt	1		1,502
Retirement of long-term debt	(35)		(1,028)
Changes in Exelon intercompany money pool	(285)		—
Distributions to member	(458)		(468)
Other financing activities	(12)		(8)
Net cash flows provided by financing activities	208		773
Increase in cash, restricted cash, and cash equivalents	435		522
Cash, restricted cash, and cash equivalents at beginning of period	327		449
Cash, restricted cash, and cash equivalents at end of period	$	762	$	971
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(37)	$	(56)
Increase in DPP	1,339		—

See the Combined Notes to Consolidated Financial Statements

16

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	721	$	226
Restricted cash and cash equivalents	41		89
Accounts receivable
Customer accounts receivable	1,857		1,330
Customer allowance for credit losses	(65)		(32)
Customer accounts receivable, net	1,792		1,298
Other accounts receivable	348		352
Other accounts receivable, net	348		352
Mark-to-market derivative assets	569		644
Receivables from affiliates	106		153
Unamortized energy contract assets	38		38
Inventories, net
Fossil fuel and emission allowances	175		233
Materials and supplies	973		978
Renewable energy credits	676		621
Assets held for sale	11		958
Other	1,290		1,357
Total current assets	6,740		6,947
Property, plant, and equipment (net of accumulated depreciation and amortization of $14,355 and $13,370 as of March 31, 2021 and December 31, 2020, respectively)	21,311		22,214
Deferred debits and other assets
Nuclear decommissioning trust funds	14,688		14,464
Investments	178		184
Goodwill	47		47
Mark-to-market derivative assets	491		555
Prepaid pension asset	1,736		1,558
Unamortized energy contract assets	285		293
Deferred income taxes	15		6
Other	1,835		1,826
Total deferred debits and other assets	19,275		18,933
Total assets(a)	$	47,326	$	48,094

See the Combined Notes to Consolidated Financial Statements

17

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	1,837	$	840
Long-term debt due within one year	699		197
Accounts payable	1,529		1,253
Accrued expenses	692		788
Payables to affiliates	125		107
Borrowings from Exelon intercompany money pool	—		285
Mark-to-market derivative liabilities	392		262
Unamortized energy contract liabilities	5		7
Renewable energy credit obligation	645		661
Liabilities held for sale	3		375
Other	371		444
Total current liabilities	6,298		5,219
Long-term debt	5,038		5,566
Long-term debt to affiliates	323		324
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	3,542		3,656
Asset retirement obligations	12,157		12,054
Non-pension postretirement benefit obligations	857		858
Spent nuclear fuel obligation	1,208		1,208
Payables to affiliates	2,865		3,017
Mark-to-market derivative liabilities	190		205
Unamortized energy contract liabilities	3		3
Other	1,405		1,308
Total deferred credits and other liabilities	22,227		22,309
Total liabilities(a)	33,886		33,418
Commitments and contingencies
Equity
Member’s equity
Membership interest	9,624		9,624
Undistributed earnings	1,554		2,805
Accumulated other comprehensive loss, net	(29)		(30)
Total member’s equity	11,149		12,399
Noncontrolling interests	2,291		2,277
Total equity	13,440		14,676
Total liabilities and equity	$	47,326	$	48,094

__________

(a)Generation’s consolidated assets include $9,967 million and $10,182 million at March 31, 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 $3,557 million and $3,572 million at March 31, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 16 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

18

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

	Three Months Ended March 31, 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

	Three Months Ended March 31, 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

See the Combined Notes to Consolidated Financial Statements

19

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Operating revenues
Electric operating revenues	$	1,475	$	1,422
Revenues from alternative revenue programs	54		12
Operating revenues from affiliates	6		5
Total operating revenues	1,535		1,439
Operating expenses
Purchased power	442		389
Purchased power from affiliate	85		97
Operating and maintenance	245		243
Operating and maintenance from affiliates	71		74
Depreciation and amortization	292		273
Taxes other than income taxes	75		75
Total operating expenses	1,210		1,151
Operating income	325		288
Other income and (deductions)
Interest expense, net	(93)		(91)
Interest expense to affiliates	(3)		(3)
Other, net	7		10
Total other income and (deductions)	(89)		(84)
Income before income taxes	236		204
Income taxes	39		36
Net income	$	197	$	168
Comprehensive income	$	197	$	168

20

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	197	$	168
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	292		273
Deferred income taxes and amortization of investment tax credits	63		42
Other non-cash operating activities	(9)		16
Changes in assets and liabilities:
Accounts receivable	23		9
Receivables from and payables to affiliates, net	(15)		(6)
Inventories	(1)		(2)
Accounts payable and accrued expenses	(176)		(147)
Collateral received (posted), net	5		3
Income taxes	(23)		(7)
Pension and non-pension postretirement benefit contributions	(171)		(143)
Other assets and liabilities	(159)		(132)
Net cash flows provided by operating activities	26		74
Cash flows from investing activities
Capital expenditures	(613)		(506)
Other investing activities	7		5
Net cash flows used in investing activities	(606)		(501)
Cash flows from financing activities
Changes in short-term borrowings	(188)		(130)
Issuance of long-term debt	700		1,000
Dividends paid on common stock	(127)		(125)
Contributions from parent	198		125
Other financing activities	(9)		(13)
Net cash flows provided by financing activities	574		857
(Decrease) increase in cash, restricted cash, and cash equivalents	(6)		430
Cash, restricted cash, and cash equivalents at beginning of period	405		403
Cash, restricted cash, and cash equivalents at end of period	$	399	$	833
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(107)	$	(5)

See the Combined Notes to Consolidated Financial Statements

21

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	86	$	83
Restricted cash and cash equivalents	270		279
Accounts receivable
Customer accounts receivable	626		656
Customer allowance for credit losses	(103)		(97)
Customer accounts receivable, net	523		559
Other accounts receivable	243		239
Other allowance for credit losses	(22)		(21)
Other accounts receivable, net	221		218
Receivables from affiliates	21		22
Inventories, net	170		170
Regulatory assets	294		279
Other	55		49
Total current assets	1,640		1,659
Property, plant, and equipment (net of accumulated depreciation and amortization of $5,811 and $5,672 as of March 31, 2021 and December 31, 2020, respectively)	24,840		24,557
Deferred debits and other assets
Regulatory assets	1,840		1,749
Investments	6		6
Goodwill	2,625		2,625
Receivables from affiliates	2,375		2,541
Prepaid pension asset	1,165		1,022
Other	334		307
Total deferred debits and other assets	8,345		8,250
Total assets	$	34,825	$	34,466

See the Combined Notes to Consolidated Financial Statements

22

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	135	$	323
Long-term debt due within one year	350		350
Accounts payable	533		683
Accrued expenses	242		390
Payables to affiliates	80		96
Customer deposits	84		86
Regulatory liabilities	360		289
Mark-to-market derivative liabilities	31		33
Other	128		143
Total current liabilities	1,943		2,393
Long-term debt	9,324		8,633
Long-term debt to financing trust	205		205
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	4,427		4,341
Asset retirement obligations	127		126
Non-pension postretirement benefits obligations	177		173
Regulatory liabilities	6,172		6,403
Mark-to-market derivative liabilities	264		268
Other	589		595
Total deferred credits and other liabilities	11,756		11,906
Total liabilities	23,228		23,137
Commitments and contingencies
Shareholders’ equity
Common stock	1,588		1,588
Other paid-in capital	8,483		8,285
Retained deficit unappropriated	(1,639)		(1,639)
Retained earnings appropriated	3,165		3,095
Total shareholders’ equity	11,597		11,329
Total liabilities and shareholders’ equity	$	34,825	$	34,466

See the Combined Notes to Consolidated Financial Statements

23

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Three Months Ended March 31, 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
	Three Months Ended March 31, 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

See the Combined Notes to Consolidated Financial Statements

24

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Operating revenues
Electric operating revenues	$	649	$	600
Natural gas operating revenues	228		209
Revenues from alternative revenue programs	10		2
Operating revenues from affiliates	2		2
Total operating revenues	889		813
Operating expenses
Purchased power	189		164
Purchased fuel	86		83
Purchased power from affiliate	41		36
Operating and maintenance	193		179
Operating and maintenance from affiliates	41		38
Depreciation and amortization	86		86
Taxes other than income taxes	43		39
Total operating expenses	679		625
Operating income	210		188
Other income and (deductions)
Interest expense, net	(35)		(33)
Interest expense to affiliates	(3)		(3)
Other, net	5		3
Total other income and (deductions)	(33)		(33)
Income before income taxes	177		155
Income taxes	10		15
Net income	$	167	$	140
Comprehensive income	$	167	$	140

See the Combined Notes to Consolidated Financial Statements

25

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	167	$	140
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	86		86
Deferred income taxes and amortization of investment tax credits	6		2
Other non-cash operating activities	12		22
Changes in assets and liabilities:
Accounts receivable	(5)		14
Receivables from and payables to affiliates, net	(2)		(3)
Inventories	13		15
Accounts payable and accrued expenses	(36)		(45)
Income taxes	3		14
Pension and non-pension postretirement benefit contributions	(16)		(16)
Other assets and liabilities	(103)		(84)
Net cash flows provided by operating activities	125		145
Cash flows from investing activities
Capital expenditures	(295)		(259)
Changes in Exelon intercompany money pool	(48)		(22)
Other investing activities	1		1
Net cash flows used in investing activities	(342)		(280)
Cash flows from financing activities
Issuance of long-term debt	375		—
Changes in Exelon intercompany money pool	(40)		—
Dividends paid on common stock	(85)		(85)
Contributions from parent	—		231
Other financing activities	(4)		—
Net cash flows provided by financing activities	246		146
Increase in cash, restricted cash, and cash equivalents	29		11
Cash, restricted cash, and cash equivalents at beginning of period	26		27
Cash, restricted cash, and cash equivalents at end of period	$	55	$	38
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(44)	$	(11)

See the Combined Notes to Consolidated Financial Statements

26

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	48	$	19
Restricted cash and cash equivalents	7		7
Accounts receivable
Customer accounts receivable	499		511
Customer allowance for credit losses	(130)		(116)
Customer accounts receivable, net	369		395
Other accounts receivable	140		130
Other allowance for credit losses	(11)		(8)
Other accounts receivable, net	129		122
Receivables from affiliates	—		2
Receivable from Exelon intercompany money pool	48		—
Inventories, net
Fossil fuel	15		33
Materials and supplies	43		38
Prepaid utility taxes	103		—
Regulatory assets	29		25
Other	22		21
Total current assets	813		662
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,897 and $3,843 as of March 31, 2021 and December 31, 2020, respectively)	10,352		10,181
Deferred debits and other assets
Regulatory assets	828		776
Investments	30		30
Receivables from affiliates	490		475
Prepaid pension asset	389		375
Other	35		32
Total deferred debits and other assets	1,772		1,688
Total assets	$	12,937	$	12,531

See the Combined Notes to Consolidated Financial Statements

27

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Long-term debt due within one year	$	300	$	300
Accounts payable	431		479
Accrued expenses	100		129
Payables to affiliates	46		50
Borrowings from Exelon intercompany money pool	—		40
Customer deposits	54		59
Regulatory liabilities	127		121
Other	31		30
Total current liabilities	1,089		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	2,297		2,242
Asset retirement obligations	29		29
Non-pension postretirement benefits obligations	286		286
Regulatory liabilities	519		503
Other	93		93
Total deferred credits and other liabilities	3,224		3,153
Total liabilities	8,322		7,998
Commitments and contingencies
Shareholder’s equity
Common stock	3,014		3,014
Retained earnings	1,601		1,519
Total shareholder’s equity	4,615		4,533
Total liabilities and shareholder's equity	$	12,937	$	12,531

See the Combined Notes to Consolidated Financial Statements

28

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)

	Three Months Ended March 31, 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
	Three Months Ended March 31, 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

See the Combined Notes to Consolidated Financial Statements

29

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Operating revenues
Electric operating revenues	$	620	$	595
Natural gas operating revenues	330		300
Revenues from alternative revenue programs	18		36
Operating revenues from affiliates	6		6
Total operating revenues	974		937
Operating expenses
Purchased power	162		114
Purchased fuel	99		76
Purchased power and fuel from affiliate	70		98
Operating and maintenance	152		146
Operating and maintenance from affiliates	45		42
Depreciation and amortization	152		143
Taxes other than income taxes	72		69
Total operating expenses	752		688
Operating income	222		249
Other income and (deductions)
Interest expense, net	(34)		(32)
Other, net	8		5
Total other income and (deductions)	(26)		(27)
Income before income taxes	196		222
Income taxes	(13)		41
Net income	$	209	$	181
Comprehensive income	$	209	$	181

See the Combined Notes to Consolidated Financial Statements

30

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	209	$	181
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	152		143
Deferred income taxes and amortization of investment tax credits	(4)		33
Other non-cash operating activities	2		(8)
Changes in assets and liabilities:
Accounts receivable	12		(28)
Receivables from and payables to affiliates, net	(15)		(13)
Inventories	9		20
Accounts payable and accrued expenses	(59)		(9)
Income taxes	(9)		7
Pension and non-pension postretirement benefit contributions	(65)		(64)
Other assets and liabilities	(103)		10
Net cash flows provided by operating activities	129		272
Cash flows from investing activities
Capital expenditures	(336)		(283)
Other investing activities	2		(6)
Net cash flows used in investing activities	(334)		(289)
Cash flows from financing activities
Changes in short-term borrowings	156		66
Dividends paid on common stock	(74)		(62)
Net cash flows provided by financing activities	82		4
Decrease in cash, restricted cash, and cash equivalents	(123)		(13)
Cash, restricted cash, and cash equivalents at beginning of period	145		25
Cash, restricted cash, and cash equivalents at end of period	$	22	$	12
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(80)	$	(35)

See the Combined Notes to Consolidated Financial Statements

31

BALTIMORE GAS AND ELECTRIC COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	21	$	144
Restricted cash and cash equivalents	1		1
Accounts receivable
Customer accounts receivable	476		487
Customer allowance for credit losses	(43)		(35)
Customer accounts receivable, net	433		452
Other accounts receivable	125		117
Other allowance for credit losses	(9)		(9)
Other accounts receivable, net	116		108
Receivables from affiliates	—		3
Inventories, net
Fossil fuel	12		25
Materials and supplies	45		41
Prepaid utility taxes	43		—
Regulatory assets	179		168
Other	9		6
Total current assets	859		948
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,115 and $4,034 as of March 31, 2021 and December 31, 2020, respectively)	10,026		9,872
Deferred debits and other assets
Regulatory assets	481		481
Investments	10		10
Prepaid pension asset	314		270
Other	69		69
Total deferred debits and other assets	874		830
Total assets	$	11,759	$	11,650

See the Combined Notes to Consolidated Financial Statements

32

BALTIMORE GAS AND ELECTRIC COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	156	$	—
Long-term debt due within one year	300		300
Accounts payable	266		346
Accrued expenses	142		205
Payables to affiliates	43		61
Customer deposits	105		110
Regulatory liabilities	41		30
Other	83		91
Total current liabilities	1,136		1,143
Long-term debt	3,365		3,364
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,609		1,521
Asset retirement obligations	24		23
Non-pension postretirement benefits obligations	182		189
Regulatory liabilities	1,016		1,109
Other	95		104
Total deferred credits and other liabilities	2,926		2,946
Total liabilities	7,427		7,453
Commitments and contingencies
Shareholder's equity
Common stock	2,318		2,318
Retained earnings	2,014		1,879
Total shareholder's equity	4,332		4,197
Total liabilities and shareholder's equity	$	11,759	$	11,650

See the Combined Notes to Consolidated Financial Statements

33

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

	Three Months Ended March 31, 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
	Three Months Ended March 31, 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

See the Combined Notes to Consolidated Financial Statements

34

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Operating revenues
Electric operating revenues	$	1,124	$	1,086
Natural gas operating revenues	71		64
Revenues from alternative revenue programs	46		18
Operating revenues from affiliates	3		3
Total operating revenues	1,244		1,171
Operating expenses
Purchased power	348		300
Purchased fuel	33		31
Purchased power from affiliates	98		104
Operating and maintenance	216		219
Operating and maintenance from affiliates	40		38
Depreciation and amortization	210		194
Taxes other than income taxes	113		114
Total operating expenses	1,058		1,000
Gain on sales of assets	—		2
Operating income	186		173
Other income and (deductions)
Interest expense, net	(67)		(67)
Other, net	17		13
Total other income and (deductions)	(50)		(54)
Income before income taxes	136		119
Income taxes	8		11
Net income	$	128	$	108
Comprehensive income	$	128	$	108

See the Combined Notes to Consolidated Financial Statements

35

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	128	$	108
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization	210		194
Deferred income taxes and amortization of investment tax credits	4		(4)
Other non-cash operating activities	(25)		7
Changes in assets and liabilities:
Accounts receivable	56		36
Receivables from and payables to affiliates, net	(18)		(17)
Inventories	5		8
Accounts payable and accrued expenses	(24)		(16)
Income taxes	3		15
Pension and non-pension postretirement benefit contributions	(36)		(27)
Other assets and liabilities	(94)		(72)
Net cash flows provided by operating activities	209		232
Cash flows from investing activities
Capital expenditures	(456)		(376)
Other investing activities	1		1
Net cash flows used in investing activities	(455)		(375)
Cash flows from financing activities
Changes in short-term borrowings	(368)		(100)
Issuance of long-term debt	625		150
Retirement of long-term debt	(44)		(6)
Changes in Exelon intercompany money pool	3		7
Distributions to member	(81)		(134)
Contributions from member	560		144
Other financing activities	(5)		(1)
Net cash flows provided by financing activities	690		60
Increase (decrease) in cash, restricted cash, and cash equivalents	444		(83)
Cash, restricted cash, and cash equivalents at beginning of period	160		181
Cash, restricted cash, and cash equivalents at end of period	$	604	$	98
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(33)	$	(57)

See the Combined Notes to Consolidated Financial Statements

36

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	558	$	111
Restricted cash and cash equivalents	37		39
Accounts receivable
Customer accounts receivable	557		611
Customer allowance for credit losses	(101)		(86)
Customer accounts receivable, net	456		525
Other accounts receivable	261		260
Other allowance for credit losses	(37)		(33)
Other accounts receivable, net	224		227
Receivables from affiliates	—		8
Inventories, net
Fossil fuel	3		6
Materials and supplies	196		198
Regulatory assets	450		440
Other	52		45
Total current assets	1,976		1,599
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,930 and $1,811 as of March 31, 2021 and December 31, 2020, respectively)	15,651		15,377
Deferred debits and other assets
Regulatory assets	1,912		1,933
Investments	141		140
Goodwill	4,005		4,005
Prepaid pension asset	383		365
Deferred income taxes	9		10
Other	310		307
Total deferred debits and other assets	6,760		6,760
Total assets(a)	$	24,387	$	23,736

See the Combined Notes to Consolidated Financial Statements

37

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	368
Long-term debt due within one year	304		347
Accounts payable	503		539
Accrued expenses	279		299
Payables to affiliates	78		104
Borrowings from Exelon intercompany money pool	24		21
Customer deposits	96		106
Regulatory liabilities	130		137
Unamortized energy contract liabilities	92		92
Other	137		141
Total current liabilities	1,643		2,154
Long-term debt	7,273		6,659
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,481		2,439
Asset retirement obligations	59		59
Non-pension postretirement benefit obligations	80		86
Regulatory liabilities	1,391		1,438
Unamortized energy contract liabilities	214		235
Other	595		622
Total deferred credits and other liabilities	4,820		4,879
Total liabilities(a)	13,736		13,692
Commitments and contingencies
Member's equity
Membership interest	10,672		10,112
Undistributed losses	(21)		(68)
Total member's equity	10,651		10,044
Total liabilities and member's equity	$	24,387	$	23,736

__________

(a)PHI’s consolidated total assets include $18 million at both March 31, 2021 and December 31, 2020 of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $21 million and $26 million at March 31, 2021 and December 31, 2020, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 16 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

38

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY

(Unaudited)

	Three Months Ended March 31, 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

	Three Months Ended March 31, 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

See the Combined Notes to Consolidated Financial Statements

39

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Operating revenues
Electric operating revenues	$	526	$	528
Revenues from alternative revenue programs	26		15
Operating revenues from affiliates	1		1
Total operating revenues	553		544
Operating expenses
Purchased power	92		85
Purchased power from affiliate	74		79
Operating and maintenance	56		60
Operating and maintenance from affiliates	52		51
Depreciation and amortization	102		95
Taxes other than income taxes	90		92
Total operating expenses	466		462
Operating income	87		82
Other income and (deductions)
Interest expense, net	(34)		(34)
Other, net	12		9
Total other income and (deductions)	(22)		(25)
Income before income taxes	65		57
Income taxes	6		5
Net income	$	59	$	52
Comprehensive income	$	59	$	52

See the Combined Notes to Consolidated Financial Statements

40

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	59	$	52
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	102		95
Deferred income taxes and amortization of investment tax credits	4		(2)
Other non-cash operating activities	(25)		(11)
Changes in assets and liabilities:
Accounts receivable	26		14
Receivables from and payables to affiliates, net	(9)		(11)
Inventories	1		3
Accounts payable and accrued expenses	—		6
Income taxes	2		6
Pension and non-pension postretirement benefit contributions	(5)		(4)
Other assets and liabilities	(58)		(38)
Net cash flows provided by operating activities	97		110
Cash flows from investing activities
Capital expenditures	(220)		(180)
Changes in PHI intercompany money pool	—		(114)
Other investing activities	1		(4)
Net cash flows used in investing activities	(219)		(298)
Cash flows from financing activities
Changes in short-term borrowings	(35)		(82)
Issuance of long-term debt	150		150
Dividends paid on common stock	(28)		(28)
Contributions from parent	138		137
Other financing activities	(1)		(1)
Net cash flows provided by financing activities	224		176
Increase (decrease) in cash, restricted cash, and cash equivalents	102		(12)
Cash, restricted cash, and cash equivalents at beginning of period	65		63
Cash, restricted cash, and cash equivalents at end of period	$	167	$	51
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(16)	$	(43)

See the Combined Notes to Consolidated Financial Statements

41

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	134	$	30
Restricted cash and cash equivalents	33		35
Accounts receivable
Customer accounts receivable	252		279
Customer allowance for credit losses	(41)		(32)
Customer accounts receivable, net	211		247
Other accounts receivable	138		131
Other allowance for credit losses	(15)		(13)
Other accounts receivable, net	123		118
Receivables from affiliates	—		2
Inventories, net	110		111
Regulatory assets	224		214
Other	19		13
Total current assets	854		770
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,746 and $3,697 as of March 31, 2021 and December 31, 2020, respectively)	7,606		7,456
Deferred debits and other assets
Regulatory assets	563		570
Investments	116		115
Prepaid pension asset	283		284
Other	71		69
Total deferred debits and other assets	1,033		1,038
Total assets	$	9,493	$	9,264

See the Combined Notes to Consolidated Financial Statements

42

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	35
Long-term debt due within one year	4		3
Accounts payable	213		226
Accrued expenses	165		164
Payables to affiliates	44		55
Customer deposits	45		51
Regulatory liabilities	39		46
Merger related obligation	33		33
Current portion of DC PLUG obligation	30		30
Other	30		31
Total current liabilities	603		674
Long-term debt	3,313		3,162
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,209		1,189
Asset retirement obligations	39		39
Non-pension postretirement benefit obligations	9		13
Regulatory liabilities	624		644
Other	324		340
Total deferred credits and other liabilities	2,205		2,225
Total liabilities	6,121		6,061
Commitments and contingencies
Shareholder's equity
Common stock	2,196		2,058
Retained earnings	1,176		1,145
Total shareholder's equity	3,372		3,203
Total liabilities and shareholder's equity	$	9,493	$	9,264

See the Combined Notes to Consolidated Financial Statements

43

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

	Three Months Ended March 31, 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

	Three Months Ended March 31, 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

See the Combined Notes to Consolidated Financial Statements

44

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Operating revenues
Electric operating revenues	$	300	$	283
Natural gas operating revenues	71		64
Revenues from alternative revenue programs	9		1
Operating revenues from affiliates	2		2
Total operating revenues	382		350
Operating expenses
Purchased power	103		88
Purchased fuel	33		31
Purchased power from affiliates	20		22
Operating and maintenance	44		42
Operating and maintenance from affiliates	39		37
Depreciation and amortization	53		48
Taxes other than income taxes	17		16
Total operating expenses	309		284
Operating income	73		66
Other income and (deductions)
Interest expense, net	(15)		(16)
Other, net	3		2
Total other income and (deductions)	(12)		(14)
Income before income taxes	61		52
Income taxes	5		7
Net income	$	56	$	45
Comprehensive income	$	56	$	45

See the Combined Notes to Consolidated Financial Statements

45

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	56	$	45
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	53		48
Deferred income taxes and amortization of investment tax credits	2		—
Other non-cash operating activities	(1)		2
Changes in assets and liabilities:
Accounts receivable	15		14
Receivables from and payables to affiliates, net	(11)		(9)
Inventories	2		3
Accounts payable and accrued expenses	11		4
Income taxes	3		7
Other assets and liabilities	(26)		(10)
Net cash flows provided by operating activities	104		104
Cash flows from investing activities
Capital expenditures	(112)		(95)
Other investing activities	—		(4)
Net cash flows used in investing activities	(112)		(99)
Cash flows from financing activities
Changes in short-term borrowings	(146)		(2)
Issuance of long-term debt	125		—
Changes in PHI intercompany money pool	—		37
Dividends paid on common stock	(40)		(52)
Contributions from parent	120		6
Other financing activities	(2)		—
Net cash flows provided by (used in) financing activities	57		(11)
Increase (decrease) in cash and cash equivalents	49		(6)
Cash and cash equivalents at beginning of period	15		13
Cash and cash equivalents at end of period	$	64	$	7
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(15)	$	(9)

See the Combined Notes to Consolidated Financial Statements

46

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	64	$	15
Accounts receivable
Customer accounts receivable	160		176
Customer allowance for credit losses	(25)		(22)
Customer accounts receivable, net	135		154
Other accounts receivable	66		68
Other allowance for credit losses	(10)		(9)
Other accounts receivable, net	56		59
Receivables from affiliates	—		1
Inventories, net
Fossil fuel	2		6
Materials and supplies	53		51
Prepaid utility taxes	10		11
Regulatory assets	65		58
Renewable energy credits	14		10
Other	2		3
Total current assets	401		368
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,563 and $1,533 as of March 31, 2021 and December 31, 2020, respectively)	4,368		4,314
Deferred debits and other assets
Regulatory assets	226		222
Goodwill	8		8
Prepaid pension asset	161		162
Other	68		66
Total deferred debits and other assets	463		458
Total assets	$	5,232	$	5,140

See the Combined Notes to Consolidated Financial Statements

47

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 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	119		126
Accrued expenses	49		46
Payables to affiliates	24		36
Customer deposits	30		32
Regulatory liabilities	49		47
Other	19		20
Total current liabilities	372		535
Long-term debt	1,720		1,595
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	734		715
Asset retirement obligations	14		14
Non-pension postretirement benefits obligations	14		15
Regulatory liabilities	474		493
Other	92		97
Total deferred credits and other liabilities	1,328		1,334
Total liabilities	3,420		3,464
Commitments and contingencies
Shareholder's equity
Common stock	1,209		1,089
Retained earnings	603		587
Total shareholder's equity	1,812		1,676
Total liabilities and shareholder's equity	$	5,232	$	5,140

See the Combined Notes to Consolidated Financial Statements

48

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

	Three Months Ended March 31, 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

	Three Months Ended March 31, 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

See the Combined Notes to Consolidated Financial Statements

49

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Operating revenues
Electric operating revenues	$	298	$	274
Revenues from alternative revenue programs	11		1
Operating revenues from affiliates	1		1
Total operating revenues	310		276
Operating expenses
Purchased power	153		126
Purchased power from affiliate	4		2
Operating and maintenance	42		45
Operating and maintenance from affiliates	34		33
Depreciation and amortization	47		43
Taxes other than income taxes	2		2
Total operating expenses	282		251
Gain on sale of assets	—		2
Operating income	28		27
Other income and (deductions)
Interest expense, net	(15)		(14)
Interest expense to affiliates, net	—		(1)
Other, net	1		2
Total other income and (deductions)	(14)		(13)
Income before income taxes	14		14
Income taxes	—		1
Net income	$	14	$	13
Comprehensive income	$	14	$	13

See the Combined Notes to Consolidated Financial Statements

50

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
(In millions)	2021		2020
Cash flows from operating activities
Net income	$	14	$	13
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	47		43
Deferred income taxes and amortization of investment tax credits	(1)		(1)
Other non-cash operating activities	(7)		4
Changes in assets and liabilities:
Accounts receivable	13		11
Receivables from and payables to affiliates, net	1		3
Inventories	3		2
Accounts payable and accrued expenses	(11)		3
Income taxes	1		2
Pension and non-pension postretirement benefit contributions	(3)		(2)
Other assets and liabilities	(3)		(22)
Net cash flows provided by operating activities	54		56
Cash flows from investing activities
Capital expenditures	(123)		(101)
Other investing activities	—		6
Net cash flows used in investing activities	(123)		(95)
Cash flows from financing activities
Changes in short-term borrowings	(187)		(16)
Issuance of long-term debt	350		—
Retirement of long-term debt	(44)		(5)
Changes in PHI intercompany money pool	—		77
Dividends paid on common stock	(14)		(23)
Contributions from parent	303		1
Other financing activities	(3)		—
Net cash flows provided by financing activities	405		34
Increase (decrease) in cash, restricted cash, and cash equivalents	336		(5)
Cash, restricted cash, and cash equivalents at beginning of period	30		28
Cash, restricted cash, and cash equivalents at end of period	$	366	$	23
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(2)	$	(4)

See the Combined Notes to Consolidated Financial Statements

51

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
ASSETS
Current assets
Cash and cash equivalents	$	353	$	17
Restricted cash and cash equivalents	4		3
Accounts receivable
Customer accounts receivable	146		156
Customer allowance for credit losses	(35)		(32)
Customer accounts receivable, net	111		124
Other accounts receivable	69		72
Other allowance for credit losses	(12)		(11)
Other accounts receivable, net	57		61
Receivables from affiliates	1		6
Inventories, net	34		37
Regulatory assets	69		75
Other	2		3
Total current assets	631		326
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,329 and $1,303 as of March 31, 2021 and December 31, 2020, respectively)	3,552		3,475
Deferred debits and other assets
Regulatory assets	407		395
Prepaid pension asset	39		40
Other	50		50
Total deferred debits and other assets	496		485
Total assets(a)	$	4,679	$	4,286

See the Combined Notes to Consolidated Financial Statements

52

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	March 31, 2021		December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	187
Long-term debt due within one year	218		261
Accounts payable	162		177
Accrued expenses	48		46
Payables to affiliates	27		31
Customer deposits	21		23
Regulatory liabilities	41		44
Other	9		11
Total current liabilities	526		780
Long-term debt	1,500		1,152
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	629		624
Non-pension postretirement benefit obligations	16		17
Regulatory liabilities	266		274
Other	48		48
Total deferred credits and other liabilities	959		963
Total liabilities(a)	2,985		2,895
Commitments and contingencies
Shareholder's equity
Common stock	1,574		1,271
Retained earnings	120		120
Total shareholder's equity	1,694		1,391
Total liabilities and shareholder's equity	$	4,679	$	4,286

__________

(a)ACE’s consolidated total assets include $13 million at both March 31, 2021 and December 31, 2020, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $16 million and $21 million at March 31, 2021 and December 31, 2020, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 16 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

53

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

	Three Months Ended March 31, 2021
(In millions)	Common Stock		Retained Earnings		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

	Three Months Ended March 31, 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

See the Combined Notes to Consolidated Financial Statements

54

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 March 31, 2021 and for the three months ended March 31, 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 disclosed. The

55

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 — Significant Accounting Policies

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 16 — 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 March 31, 2021, the total unpaid aggregate preferred distributions and related return owed to Generation is $632 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.

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

56

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(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. Completion of the transaction is expected in the second half of 2021 and is subject to various customary closing conditions.

As a result, in the second quarter of 2021, Exelon and Generation will reclassify these assets and liabilities as held for sale and expect to record an impairment loss in a range of $135 million to $150 million on a pre-tax basis, which will be recorded within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

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.

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
BGE - Maryland(b)	May 15, 2020 (amended September 11, 2020)	Electric	137		81		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	91		21		9.65	%

__________

(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 in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million in 2021, 2022, and 2023, respectively. However, the MDPSC utilized certain tax benefits to fully offset the increases in 2021 so 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 revenue requirement increases in 2022 and 2023 and BGE cannot predict the outcome.

57

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(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	$	51	7.36	%	Fourth quarter of 2021
PECO - Pennsylvania	March 30, 2021	Electric	246		10.95	%	Fourth quarter of 2021
PECO - Pennsylvania	September 30, 2020	Natural Gas	69		10.95	%	Second quarter of 2021
Pepco - District of Columbia(b)	May 30, 2019 (amended June 1, 2020)	Electric	136		9.7	%	Second quarter of 2021
Pepco - Maryland(c)	October 26, 2020 (amended March 31, 2021)	Electric	104		10.2	%	Second quarter of 2021
DPL - Delaware(d)	March 6, 2020 (amended February 2, 2021)	Electric	23		10.3	%	Third quarter of 2021
ACE - New Jersey(e)	December 9, 2020 (amended February 26, 2021)	Electric	67		10.3	%	Fourth 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)Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects a three-year cumulative multi-year plan for 2020 through 2022 and requested revenue requirement increases of $73 million in 2022 and $63 million in 2023, to recover capital investments made during 2018 through 2020 and planned capital investments through the end of 2022.

(c)Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024 and total requested revenue requirement increases of $52 million effective April 1, 2023 and $52 million effective April 1, 2024 to recover capital investments made in 2019 and 2020 and planned capital investments through March 31, 2024.

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

(e)Requested increases are before New Jersey sales and use tax. ACE intends to put rates into effect on September 8, 2021 subject to refund.

Transmission Formula Rates

For 2021, the following total increases were included in ComEd’s electric transmission formula rate update. PECO, BGE, Pepco, DPL, and ACE intend to file by the required deadline for the annual update.

Registrant(a)	Initial Revenue Requirement Increase		Annual Reconciliation Increase		Total Revenue Requirement Increase		Allowed Return on Rate Base(b)		Allowed ROE(c)
ComEd	$	33	$	12	$	45	8.20	%	11.50	%

(a)Rates are effective June 30, 2021 - May 31, 2022, subject to review by interested parties pursuant to review protocols of ComEd's tariff.

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

(c)As part of the FERC-approved settlements of ComEd’s 2007 rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%.

58

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Regulatory Matters

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 $106 million primarily due to an increase of $55 million in the Electric Distribution Formula Rate Annual Reconciliations regulatory asset, and $38 million in the Energy Efficiency Costs regulatory asset.

PECO. Regulatory assets increased $56 million primarily due to an increase of $48 million in the Deferred Income Taxes regulatory asset and $9 million in the Vacation Accrual regulatory asset.

BGE. Regulatory liabilities decreased $82 million primarily due to a decrease of $93 million in the Deferred Income Taxes regulatory liability, partially offset by an increase of $9 million in the Electric Energy and Natural Gas Costs 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
March 31, 2021	$	49	$	—	$	—	$	43	$	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.

The estimated impact to Exelon’s and Generation’s Net income for the first quarter of 2021 arising from these market and weather conditions was a reduction of approximately $880 million. The ultimate impact to Exelon’s and Generation’s consolidated financial statements for the full year 2021 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.

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 32 hours between February 18 and February 19 after firm load shedding ceased and to cap ancillary services at $9,000 per MWh. Appeals of certain of the PUCT’s orders also have been filed in state court. On April 19, 2021, Generation filed a declaratory action and appeal in state court challenging the PUCT’s orders setting prices at

59

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Regulatory Matters

$9,000 per MWh. 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, resulting in approximately a $2.9 billion payment shortfall in collections, which is allocated to the remaining ERCOT market participants. Generation recorded its portion of this obligation of approximately $28 million on a discounted basis in the first quarter of 2021, which is to be paid over a term of 96 years. Current ERCOT rules limit recovery of default from market participants to $2.5 million per month market-wide. In February 2021, the PUCT gave ERCOT discretion to disregard its current rules, but ERCOT has declined to exercise that discretion thus far. Generation's request for rehearing of this PUCT order was denied on April 17, 2021 and an appeal is pending in state court. Additionally, several pending legislative proposals were introduced in the Texas legislature during February and March 2021 concerning the amount, timing and allocation of recovery of the $2.9 billion shortfall. Exelon and Generation are monitoring the proposed legislation and cannot predict the outcome or the financial statement impact.

In addition, several other legislative proposals have been introduced in the Texas legislature during February and March 2021 addressing cold-weather preparation for power plants and natural gas production and transportation infrastructure. The proposed legislation provides the PUCT and the Railroad Commission of Texas with the option of imposing fines if the new proposed standards are not met. Exelon and Generation are monitoring the proposed legislation and cannot predict the outcome. However, such proposed legislation could have a material adverse impact in Exelon’s and Generation’s consolidated financial statements.

In February 2021, more than 70 local distribution companies (LDCs) in multiple states throughout the mid-continent region, where Generation serves natural gas transportation customers, issued operational flow orders (OFOs), curtailments or other limitations on natural gas use to preserve adequate pressure on the system. When in effect, gas use above these limitations is severely penalized according to the LDCs’ tariff. Gas 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 are either voluntarily waiving or seeking regulatory approvals to waive the penalties associated with these restrictions. During March 2021, three natural gas pipelines filed individual petitions with the FERC requesting approval to waive these penalties. Generation also filed motions in March 2021 to intervene with the FERC in support of these requests from the pipelines. On March 25, 2021, the FERC issued an order on one of the petitions approving the request to waive the penalties for February 15, 2021. On April 23, 2021, Generation and several other entities filed a request for rehearing and a complaint to expand the order to include additional days of the weather events in February, from February 15 through February 19, 2021. On April 9, 2021 and April 19, 2021, the FERC issued orders on the remaining petitions approving the requests to waive the penalties. Exelon and Generation cannot predict the outcome of the FERC proceeding or the determinations made by the LDCs.

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 of appeal of the Superior Court’s order to the New Jersey Supreme Court. Exelon and Generation cannot predict the outcome of 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. See Note 7 — Early Plant Retirements for additional information related to Salem.

New England Regulatory Matters

60

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Regulatory Matters

Mystic Units 8 & 9 and Everett Marine Terminal Cost of Service Agreement (Exelon and Generation). 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 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.

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

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.

61

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Regulatory Matters

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.

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 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 months ended March 31, 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
	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

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.

62

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Revenue from Contracts with Customers

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 months ended March 31, 2021 and 2020. As of March 31, 2021 and December 31, 2020, ComEd's, PECO's, and BGE's contract liabilities were immaterial.

	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
	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	$	—	$	—	$	—	$	—

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

	Three Months Ended March 31,
	2021		2020
Exelon	$	17	$	9
Generation	39		19
PHI	2		—
Pepco	2		—

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 March 31, 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	$	233	$	100	$	56	$	41	$	330	$	760
Generation	286		131		56		35		243		751
PHI	7		8		8		6		87		116
Pepco	5		6		6		5		70		92
DPL	1		1		1		—		9		12
ACE	1		1		1		1		8		12

63

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(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,

64

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(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 months ended March 31, 2021 and 2020 is as follows:

Three Months Ended March 31, 2021 and 2020

	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2021
Competitive businesses electric revenues	$	4,187	$	—	$	—	$	—	$	—	$	—	$	(293)	$	3,894
Competitive businesses natural gas revenues	1,326		—		—		—		—		—				1,326
Competitive businesses other revenues	46		—		—		—		—		—		(1)		45
Rate-regulated electric revenues	—		1,535		661		632		1,170		—		(10)		3,988
Rate-regulated natural gas revenues	—		—		228		342		71		—		(4)		637
Shared service and other revenues	—		—		—		—		3		491		(494)		—
Total operating revenues	$	5,559	$	1,535	$	889	$	974	$	1,244	$	491	$	(802)	$	9,890
2020
Competitive businesses electric revenues	$	3,752	$	—	$	—	$	—	$	—	$	—	$	(326)	$	3,426
Competitive businesses natural gas revenues	672		—		—		—		—		—		(3)		669
Competitive businesses other revenues	309		—		—		—		—		—		(1)		308
Rate-regulated electric revenues	—		1,439		604		613		1,104		—		(12)		3,748
Rate-regulated natural gas revenues	—		—		209		324		64		—		(2)		595
Shared service and other revenues	—		—		—		—		3		480		(482)		1
Total operating revenues	$	4,733	$	1,439	$	813	$	937	$	1,171	$	480	$	(826)	$	8,747
Intersegment revenues(c):
2021	$	295	$	6	$	2	$	6	$	3	$	487	$	(799)	$	—
2020	330		5		2		6		3		479		(824)		1
Depreciation and amortization:

65

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
2021	$	940	$	292	$	86	$	152	$	210	$	17	$	—	$	1,697
2020	304		273		86		143		194		21		—		1,021
Operating expenses:
2021	$	6,672	$	1,210	$	679	$	752	$	1,058	$	492	$	(781)	$	10,082
2020	4,400		1,151		625		688		1,000		481		(816)		7,529
Interest expense, net:
2021	$	72	$	96	$	38	$	34	$	67	$	79	$	—	$	386
2020	109		94		36		32		67		72		—		410
Income (loss) before income taxes:
2021	$	(947)	$	236	$	177	$	196	$	136	$	(80)	$	—	$	(282)
2020	(547)		204		155		222		119		(69)		1		85
Income Taxes:
2021	$	(179)	$	39	$	10	$	(13)	$	8	$	116	$	—	$	(19)
2020	(389)		36		15		41		11		(8)		—		(294)
Net income (loss):
2021	$	(769)	$	197	$	167	$	209	$	128	$	(196)	$	—	$	(264)
2020	(161)		168		140		181		108		(61)		1		376
Capital Expenditures:
2021	$	382	$	613	$	295	$	336	$	456	$	58	$	—	$	2,140
2020	558		506		259		283		376		34		—		2,016
Total assets:
March 31, 2021	$	47,326	$	34,825	$	12,937	$	11,759	$	24,387	$	8,788	$	(10,022)	$	130,000
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 17 — Supplemental Financial Information for additional information on total utility taxes.

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

66

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	$	553	$	311	$	310	$	—	$	(4)	$	1,170
Rate-regulated natural gas revenues	—		71		—		—		—		71
Shared service and other revenues	—		—		—		95		(92)		3
Total operating revenues	$	553	$	382	$	310	$	95	$	(96)	$	1,244
2020
Rate-regulated electric revenues	$	544	$	286	$	276	$	—	$	(2)	$	1,104
Rate-regulated natural gas revenues	—		64		—		—		—		64
Shared service and other revenues	—		—		—		93		(90)		3
Total operating revenues	$	544	$	350	$	276	$	93	$	(92)	$	1,171
Intersegment revenues(c):
2021	$	1	$	2	$	1	$	95	$	(96)	$	3
2020	1		2		1		92		(93)		3
Depreciation and amortization:
2021	$	102	$	53	$	47	$	8	$	—	$	210
2020	95		48		43		9		(1)		194
Operating expenses:
2021	$	466	$	309	$	282	$	97	$	(96)	$	1,058
2020	462		284		251		93		(90)		1,000
Interest expense, net:
2021	$	34	$	15	$	15	$	3	$	—	$	67
2020	34		16		15		3		(1)		67
Income (loss) before income taxes:
2021	$	65	$	61	$	14	$	(4)	$	—	$	136
2020(d)	57		52		14		(4)		—		119
Income Taxes:
2021	$	6	$	5	$	—	$	(3)	$	—	$	8
2020	5		7		1		(2)		—		11
Net income (loss):
2021	$	59	$	56	$	14	$	(1)	$	—	$	128
2020	52		45		13		(2)		—		108
Capital Expenditures:
2021	$	220	$	112	$	123	$	1	$	—	$	456
2020	180		95		101		—		—		376
Total assets:
March 31, 2021	$	9,493	$	5,232	$	4,679	$	5,020	$	(37)	$	24,387
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 17 — Supplemental Financial Information for additional information on total utility taxes.

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

(d)The Income (loss) before income taxes in Other and Intersegment Eliminations have been adjusted by an offsetting $110 million in 2020.

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

67

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.

Competitive Business Revenues (Generation):

	Three Months Ended March 31, 2021
	Revenues from external customers(a)						Intersegment Revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	1,174	$	(14)	$	1,160	$	5	$	1,165
Midwest	1,009		(11)		998		—		998
New York	382		(45)		337		—		337
ERCOT	353		(101)		252		5		257
Other Power Regions	1,172		268		1,440		(10)		1,430
Total Competitive Businesses Electric Revenues	4,090		97		4,187		—		4,187
Competitive Businesses Natural Gas Revenues	864		462		1,326		—		1,326
Competitive Businesses Other Revenues(c)	89		(43)		46		—		46
Total Generation Consolidated Operating Revenues	$	5,043	$	516	$	5,559	$	—	$	5,559

	Three Months Ended March 31, 2020
	Revenues from external customers(a)						Intersegment revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	1,264	$	(96)	$	1,168	$	6	$	1,174
Midwest	944		64		1,008		(6)		1,002
New York	335		(21)		314		—		314
ERCOT	155		28		183		7		190
Other Power Regions	1,007		72		1,079		(7)		1,072
Total Competitive Businesses Electric Revenues	3,705		47		3,752		—		3,752
Competitive Businesses Natural Gas Revenues	503		169		672		—		672
Competitive Businesses Other Revenues(c)	99		210		309		—		309
Total Generation Consolidated Operating Revenues	$	4,307	$	426	$	4,733	$	—	$	4,733

__________

(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 $84 million and gains of $179 million in 2021 and 2020, respectively, and elimination of intersegment revenues.

68

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):

	Three Months Ended March 31, 2021						Three Months Ended March 31, 2020
	RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	562	$	5	$	567	$	559	$	8	$	567
Midwest	702		—		702		732		(5)		727
New York	240		2		242		189		4		193
ERCOT	(1,036)		(148)		(1,184)		76		4		80
Other Power Regions	250		(33)		217		177		(19)		158
Total Revenues net of purchased power and fuel expense for Reportable Segments	718		(174)		544		1,733		(8)		1,725
Other(b)	231		174		405		296		8		304
Total Generation Revenues net of purchased power and fuel expense	$	949	$	—	$	949	$	2,029	$	—	$	2,029

__________

(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 $175 million and gains of $132 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 $54 million in 2021; and

• the elimination of intersegment RNF.

69

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):

	Three Months Ended March 31, 2021
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	741	$	433	$	362	$	605	$	253	$	190	$	162
Small commercial & industrial	367		100		69		118		33		46		39
Large commercial & industrial	134		57		105		248		184		21		43
Public authorities & electric railroads	11		9		7		13		6		4		3
Other(a)	220		52		77		143		51		41		52
Total rate-regulated electric revenues(b)	$	1,473	$	651	$	620	$	1,127	$	527	$	302	$	299
Rate-regulated natural gas revenues
Residential	$	—	$	160	$	216	$	46	$	—	$	46	$	—
Small commercial & industrial	—		59		35		18		—		18		—
Large commercial & industrial	—		—		54		2		—		2		—
Transportation	—		7		—		4		—		4		—
Other(c)	—		2		31		1		—		1		—
Total rate-regulated natural gas revenues(d)	$	—	$	228	$	336	$	71	$	—	$	71	$	—
Total rate-regulated revenues from contracts with customers	$	1,473	$	879	$	956	$	1,198	$	527	$	373	$	299
Other revenues
Revenues from alternative revenue programs	$	54	$	10	$	18	$	46	$	26	$	9	$	11
Other rate-regulated electric revenues(e)	8		—		—		—		—		—		—
Other rate-regulated natural gas revenues(e)	—		—		—		—		—		—		—
Total other revenues	$	62	$	10	$	18	$	46	$	26	$	9	$	11
Total rate-regulated revenues for reportable segments	$	1,535	$	889	$	974	$	1,244	$	553	$	382	$	310

70

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

	Three Months Ended March 31, 2020
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	701	$	382	$	339	$	534	$	236	$	161	$	137
Small commercial & industrial	362		99		67		115		35		43		37
Large commercial & industrial	134		53		103		253		188		23		42
Public authorities & electric railroads	13		7		7		15		9		3		3
Other(a)	211		58		79		169		60		54		55
Total rate-regulated electric revenues(b)	$	1,421	$	599	$	595	$	1,086	$	528	$	284	$	274
Rate-regulated natural gas revenues
Residential	$	—	$	150	$	206	$	40	$	—	$	40	$	—
Small commercial & industrial	—		51		34		17		—		17		—
Large commercial & industrial	—		—		51		1		—		1		—
Transportation	—		6		—		4		—		4		—
Other(c)	—		1		9		2		—		2		—
Total rate-regulated natural gas revenues(d)	$	—	$	208	$	300	$	64	$	—	$	64	$	—
Total rate-regulated revenues from contracts with customers	$	1,421	$	807	$	895	$	1,150	$	528	$	348	$	274
Other revenues
Revenues from alternative revenue programs	$	12	$	2	$	36	$	18	$	15	$	1	$	1
Other rate-regulated electric revenues(e)	6		3		3		3		1		1		1
Other rate-regulated natural gas revenues(e)	—		1		3		—		—		—		—
Total other revenues	$	18	$	6	$	42	$	21	$	16	$	2	$	2
Total rate-regulated revenues for reportable segments	$	1,439	$	813	$	937	$	1,171	$	544	$	350	$	276

__________

(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:

•$6 million, $5 million at ComEd

•$1 million, $2 million at PECO

•$2 million, $6 million at BGE

•$3 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 for both 2021 and 2020

•$4 million, $3 million at BGE

(e)Includes late payment charge revenues.

71

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 March 31, 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(a)	104		34		21		20		9		20		11		6		3
Less: Write-offs, net of recoveries(b)	28		1		15		6		1		5		2		3		—
Balance as of March 31, 2021	$	442	$	65	$	103	$	130	$	43	$	101	$	41	$	25	$	35
	Three Months Ended March 31, 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	55		4		18		18		8		7		3		2		2
Less: Write-offs, net of recoveries(b)	20		3		6		7		2		2		1		—		1
Balance as of March 31, 2020	$	278	$	81	$	71	$	66	$	18	$	42	$	15	$	13	$	14

_________

(a)For Generation, primarily relates to the impacts of the February 2021 extreme cold weather event. See Note 3 — Regulatory Matters for additional information. For the Utility Registrants, the increase is primarily as a result of increased receivable balances due to the colder weather and the increased aging of receivables, the temporary suspension of customer disconnections for non-payment, temporary cessation of new late payment fees, and reconnection of service to customers previously disconnected due to COVID-19.

(b)Recoveries were not material to the Registrants.

72

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 March 31, 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	10		—		1		4		1		4		2		1		1
Less: Write-offs, net of recoveries(a)	2		—		—		1		1		—		—		—		—
Balance as of March 31, 2021	$	79	$	—	$	22	$	11	$	9	$	37	$	15	$	10	$	12
	Three Months Ended March 31, 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	8		—		3		1		2		2		1		—		1
Less: Write-offs, net of recoveries(a)	4		—		1		1		2		—		—		—		—
Balance as of March 31, 2020	$	52	$	—	$	22	$	7	$	5	$	18	$	8	$	4	$	6

_________

(a)Recoveries were not material to the Registrants.

Unbilled Customer Revenue (All Registrants)

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

	Unbilled customer revenues(a)
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2021	$	1,178	$	671	$	161	$	102	$	126	$	118	$	58	$	38	$	22
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.

73

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

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

On February 17, 2021, Generation received additional cash of $250 million from the Purchasers for the remaining available funding in the Facility.

On March 31, 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.

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

	March 31, 2021		December 31, 2020
Derecognized receivables transferred at fair value	$	1,301	$	1,139
Cash proceeds received	900		500
DPP	401		639

	Three Months Ended March 31, 2021
Loss on sale of receivables(a)	$	17

_________

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

	Three Months Ended March 31, 2021
Proceeds from new transfers(a)	$	1,036
Cash collections received on DPP and reinvested in the Facility(b)	1,174
Cash collections reinvested in the Facility	2,210

_________

(a)Customer accounts receivable sold into the Facility were $2,375 million for the three months ended March 31, 2021.

(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 Statement of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities of the Consolidated Statement of Cash Flows.

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

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

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

74

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

	Three Months Ended March 31, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total receivables purchased	$	1,011	$	—	$	266	$	290	$	199	$	268	$	166	$	56	$	46
Total receivables sold	69		81		—		—		—		—		—		—		—
Related party transactions:
Receivables purchased from Generation	—		—		—		—		12		—		—		—		—
Receivables sold to the Utility Registrants	—		12		—		—		—		—		—		—		—

	Three Months Ended March 31, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total receivables purchased	$	781	$	—	$	280	$	284	$	195	$	264	$	165	$	53	$	46
Total receivables sold	507		749		—		—		—		—		—		—		—
Related party transactions:
Receivables purchased from Generation	—		—		34		67		69		72		51		13		8
Receivables sold to the Utility Registrants	—		242		—		—		—		—		—		—		—

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.

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

75

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Early Plant Retirements

Jersey ZEC program unless Illinois and New Jersey implement an FRR mechanism under which the Generation plants in these states would be removed from PJM’s capacity auction. See Note 3 — Regulatory Matters for additional information on the New Jersey ZEC program and 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.

Generation’s Dresden, Byron, and Braidwood 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. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. While all of LaSalle's capacity did clear in the 2021-2022 planning year auction, Generation has become increasingly concerned about the economic viability of this plant as well in a landscape where energy market prices remain depressed and energy market rules remain fatally flawed.

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.

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 months ended March 31, 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 March 31, 2021(a)
Depreciation and amortization
Accelerated depreciation(a)	$	620
Accelerated nuclear fuel amortization	54
Operating and maintenance
Other charges	2
Contractual offset(b)	(226)
Total	$	450

_________

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

(b)Reflects contractual offset for ARO accretion and ARC depreciation. Based on the regulatory agreement with the ICC, decommissioning-related activities in the first quarter of 2021 have been offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset in 2021 resulted in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 10 - Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information.

76

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 March 31, 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 March 31, 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	$	83	$	103	$	186
Nuclear fuel inventory, net	165		264		429
Completed plant, net	1,379		1,566		2,945
Construction work in progress	33		70		103
Liability Balances
Asset retirement obligation	(577)		(964)		(1,541)
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 $20 million for the three months ended March 31, 2021.

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

77

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 8 — Nuclear Decommissioning

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 March 31, 2021:

Nuclear decommissioning ARO at December 31, 2020(a)	$	11,922
Accretion expense	124
Costs incurred related to decommissioning plants	(20)
Nuclear decommissioning ARO at March 31, 2021(a)	$	12,026

_________

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

NDT Funds

Exelon and Generation had NDT funds totaling $14,927 million and $14,599 million at March 31, 2021 and December 31, 2020, respectively. The NDT funds also include $239 million and $134 million for the current portion of the NDT funds at March 31, 2021 and December 31, 2020, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 17 — Supplemental Financial Information for additional information on activities of the NDT funds.

NRC Minimum Funding Requirements

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

Generation filed its biennial decommissioning funding status report with the NRC on 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. Generation stated that it intends to submit its PSDAR with additional decommissioning cost information by July 1, 2021, for Byron Units 1 and 2, and will evaluate the status of funding assurance based on the updated cost information and provide additional funding assurance by the time of shutdown if required.

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.

78

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Income Taxes

9. Income Taxes (All Registrants)

Rate Reconciliation

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

	Three Months Ended March 31, 2021
	Exelon(a)	Generation(a)	ComEd(b)	PECO(b)	BGE(b),(c)	PHI(b)	Pepco(b)	DPL(b)	ACE(b)
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	14.6	4.4	6.8	(1.6)	(10.1)	6.1	5.5	6.4	6.9
Qualified NDT fund income	(18.4)	(5.5)	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	2.4	0.6	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	8.8	—	(0.6)	(10.5)	(1.4)	(1.5)	(2.1)	(0.7)	(0.9)
Production tax credits and other credits	6.7	1.8	(0.2)	—	(0.4)	(0.2)	(0.2)	(0.1)	(0.3)
Noncontrolling interests	0.6	0.2	—	—	—	—	—	—	—
Excess deferred tax amortization	27.9	—	(6.9)	(3.2)	(15.5)	(19.3)	(15.1)	(18.5)	(28.7)
Other(d)	(56.9)	(3.6)	(3.5)	(0.1)	(0.1)	(0.1)	0.1	0.3	2.2
Effective income tax rate	6.7%	18.9%	16.5%	5.6%	(6.6)%	5.9%	9.2%	8.2%	—%

	Three Months Ended March 31, 2020
	Exelon(b)	Generation(e)	ComEd(b)	PECO(b)	BGE(b)	PHI(b)	Pepco(b)	DPL(b)	ACE(b)
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	34.0	0.7	8.3	0.1	5.7	5.8	4.7	6.6	6.7
Qualified NDT fund income	(235.8)	36.4	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(4.5)	0.5	(0.2)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(23.0)	—	(1.1)	(8.4)	(1.2)	(1.4)	(2.1)	(0.7)	(0.8)
Production tax credits and other credits	(9.9)	1.3	(0.2)	—	(0.2)	—	—	—	—
Noncontrolling interests	10.6	(1.6)	—	—	—	—	—	—	—
Excess deferred tax amortization	(71.7)	—	(10.5)	(3.0)	(7.3)	(15.5)	(14.2)	(12.7)	(18.8)
Tax Settlements	(79.1)	12.2	—	—	—	—	—	—	—
Other	12.5	0.6	0.3	—	0.6	(0.6)	(0.6)	(0.5)	(0.8)
Effective income tax rate	(345.9)%	71.1%	17.6%	9.7%	18.5%	9.2%	8.8%	13.5%	7.1%

79

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Income Taxes

__________

(a)Exelon and Generation recognized a loss before income taxes for the quarter ended March 31, 2021. As a result, positive percentages represent an income tax benefit for the period presented.

(b)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

(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 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.

(e)Generation recognized a loss before income taxes for the quarter ended March 31, 2020. As a result, positive percentages represent an income tax benefit for the period presented.

Unrecognized Tax Benefits

PHI and ACE have the following unrecognized tax benefits as of March 31, 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
March 31, 2021	$	52	$	15
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 March 31, 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.

10. 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 months ended March 31, 2021 and 2020.

80

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Retirement Benefits

	Pension Benefits				OPEB
	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	110	$	97	$	21	$	23
Interest cost	161		189		28		38
Expected return on assets	(336)		(318)		(40)		(41)
Amortization of:
Prior service cost (credit)	1		1		(8)		(31)
Actuarial loss	150		128		9		12
Curtailment benefits	—		—		(1)		—
Net periodic benefit cost	$	86	$	97	$	9	$	1

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 March 31,
Pension and OPEB Costs	2021		2020
Exelon	$	95	$	98
Generation	26		27
ComEd	32		28
PECO	2		1
BGE	15		16
PHI	12		17
Pepco	2		3
DPL	1		1
ACE	3		3

Defined Contribution Savings Plans

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans for the three months ended March 31, 2021 and 2020, respectively.

	Three Months Ended March 31,
Savings Plans Matching Contributions	2021		2020
Exelon	$	33	$	33
Generation	13		13
ComEd	8		7
PECO	3		3
BGE	2		2
PHI	3		3
Pepco	1		1
DPL	1		1

81

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

11. Derivative Financial Instruments (All Registrants)

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

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

82

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

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

Registrant	Commodity	Accounting Treatment	Hedging Instrument
ComEd	Electricity	NPNS	Fixed price contracts based on all requirements in the IPA procurement plans.
	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)	20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO	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 March 31, 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 March 31, 2021 and December 31, 2020:

	Exelon		Generation										ComEd
March 31, 2021	Total Derivatives		Economic Hedges		Proprietary Trading		Collateral(a)(b)		Netting(a)		Subtotal		Economic Hedges
Mark-to-market derivative assets (current assets)	$	569	$	2,566	$	28	$	24	$	(2,049)	$	569	$	—
Mark-to-market derivative assets (noncurrent assets)	488		1,400		5		45		(962)		488		—
Total mark-to-market derivative assets	1,057		3,966		33		69		(3,011)		1,057		—
Mark-to-market derivative liabilities (current liabilities)	(418)		(2,472)		(13)		49		2,049		(387)		(31)
Mark-to-market derivative liabilities (noncurrent liabilities)	(454)		(1,179)		(1)		28		962		(190)		(264)
Total mark-to-market derivative liabilities	(872)		(3,651)		(14)		77		3,011		(577)		(295)
Total mark-to-market derivative net assets (liabilities)	$	185	$	315	$	19	$	146	$	—	$	480	$	(295)

83

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — 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)Of the collateral posted, $148 million and $209 million represents variation margin on the exchanges as of March 31, 2021 and December 31, 2020 respectively.

Economic Hedges (Commodity Price Risk)

Generation. For the three months ended March 31, 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 March 31,
	2021		2020
Income Statement Location	Gain (Loss)
Operating revenues	$	(83)	$	175
Purchased power and fuel	265		(47)
Total Exelon and Generation	$	182	$	128

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 March 31, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% 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 months ended March 31, 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.

84

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — 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 $563 million and $665 million for Exelon and Generation as of March 31, 2021 and December 31, 2020, respectively.

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

85

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — 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 March 31, 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 March 31, 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	$	431	$	31	$	400	—	$	—
Non-investment grade	43		4		39
No external ratings
Internally rated — investment grade	146		1		145
Internally rated — non-investment grade	70		25		45
Total	$	690	$	61	$	629	—	$	—

Net Credit Exposure by Type of Counterparty	As of March 31, 2021
Investor-owned utilities, marketers, power producers	$	451
Energy cooperatives and municipalities	123
Other	55
Total	$	629

_________ 

(a)As of March 31, 2021, credit collateral held from counterparties where Generation had credit exposure included $32 million of cash and $29 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 March 31, 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.

86

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — 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	March 31, 2021		December 31, 2020
Gross fair value of derivative contracts containing this feature(a)	$	(948)	$	(834)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)	518		537
Net fair value of derivative contracts containing this feature(c)	$	(430)	$	(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 March 31, 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.

	March 31, 2021		December 31, 2020
Cash collateral posted	$	232	$	511
Letters of credit posted	242		226
Cash collateral held	101		110
Letters of credit held	41		40
Additional collateral required in the event of a credit downgrade below investment grade	1,379		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 March 31, 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 March 31, 2021, they could have been required to post incremental collateral to its counterparties of $32 million, $48 million and $12 million, respectively.

87

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 12 — Debt and Credit Agreements

12. Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

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

Commercial Paper

The following table reflects the Registrants' commercial paper programs as of March 31, 2021 and December 31, 2020. PECO had no commercial paper borrowings as of both March 31, 2021 and December 31, 2020.

	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	March 31, 2021		December 31, 2020		March 31, 2021		December 31, 2020
Exelon(a)(b)	$	1,628	$	1,031	0.52	%	0.25	%
Generation(b)	1,337		340		0.60	%	0.27	%
ComEd	135		323		0.16	%	0.23	%
BGE	156		—		0.15	%	—	%
PHI(c)	—		368		—	%	0.24	%
Pepco	—		35		—	%	0.22	%
DPL	—		146		—	%	0.24	%
ACE	—		187		—	%	0.25	%

__________

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

(b)Higher outstanding commercial paper primarily driven by increased liquidity needs from the February 2021 extreme cold weather event. See Note 3 – Regulatory Matters for additional information.

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

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.

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.

88

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 12 — Debt and Credit Agreements

On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement 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.

Long-Term Debt

Issuance of Long-Term Debt

During the three months ended March 31, 2021, the following long-term debt was issued:

Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Exelon	Long-Term Software License Agreements	3.62	%	December 1, 2025	$	4	Procurement of software licenses.
Generation	Energy Efficiency Project Financing(a)	2.53	%	May 31, 2021	1		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.
Pepco(b)	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)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

(b)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 March 31, 2021, the Registrants are in compliance with debt covenants.

89

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

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

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

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

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

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

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 March 31, 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.

	March 31, 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	$	38,529	$	39,255	$	3,115	$	42,370	$	36,912	$	40,688	$	3,064	$	43,752
Generation	6,060		5,497		1,158		6,655		6,087		5,648		1,208		6,856
ComEd	9,674		10,853		—		10,853		8,983		11,117		—		11,117
PECO	4,125		4,491		50		4,541		3,753		4,553		50		4,603
BGE	3,665		3,991		—		3,991		3,664		4,366		—		4,366
PHI	7,577		6,050		1,907		7,957		7,006		6,099		1,806		7,905
Pepco	3,317		3,112		823		3,935		3,165		3,336		748		4,084
DPL	1,802		1,386		524		1,910		1,677		1,484		455		1,939
ACE	1,718		1,302		560		1,862		1,413		1,018		602		1,620
Long-Term Debt to Financing Trusts(a)
Exelon	$	390	$	—	$	465	$	465	$	390	$	—	$	467	$	467
ComEd	205		—		243		243		205		—		246		246
PECO	184		—		222		222		184		—		221		221
SNF Obligation
Exelon	$	1,208	$	979	$	—	$	979	$	1,208	$	909	$	—	$	909
Generation	1,208		979		—		979		1,208		909		—		909

__________

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

90

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

Recurring Fair Value Measurements

The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2021 and December 31, 2020:

Exelon and Generation

	Exelon										Generation
As of March 31, 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)	$	968	$	—	$	—	$	—	$	968	$	125	$	—	$	—	$	—	$	125
NDT fund investments
Cash equivalents(b)	509		95		—		—		604		509		95		—		—		604
Equities	4,439		1,574		—		1,555		7,568		4,439		1,574		—		1,555		7,568
Fixed income
Corporate debt(c)	—		1,023		283		—		1,306		—		1,023		283		—		1,306
U.S. Treasury and agencies	2,030		41		—		—		2,071		2,030		41		—		—		2,071
Foreign governments	—		51		—		—		51		—		51		—		—		51
State and municipal debt	—		40		—		—		40		—		40		—		—		40
Other	40		35		—		1,285		1,360		40		35		—		1,285		1,360
Fixed income subtotal	2,070		1,190		283		1,285		4,828		2,070		1,190		283		1,285		4,828
Private credit	—		—		196		617		813		—		—		196		617		813
Private equity	—		—		—		532		532		—		—		—		532		532
Real estate	—		—		—		686		686		—		—		—		686		686
NDT fund investments subtotal(d)(e)	7,018		2,859		479		4,675		15,031		7,018		2,859		479		4,675		15,031
Rabbi trust investments
Cash equivalents	60		—		—		—		60		4		—		—		—		4
Mutual funds	95		—		—		—		95		31		—		—		—		31
Fixed income	—		10		—		—		10		—		—		—		—		—
Life insurance contracts	—		89		35		—		124		—		29		—		—		29
Rabbi trust investments subtotal	155		99		35		—		289		35		29		—		—		64
Investments in equities(f)	177		—		—		—		177		177		—		—		—		177
Commodity derivative assets
Economic hedges	478		1,748		1,740		—		3,966		478		1,748		1,740		—		3,966
Proprietary trading	—		16		17		—		33		—		16		17		—		33
Effect of netting and allocation of collateral(g)(h)	(356)		(1,387)		(1,199)		—		(2,942)		(356)		(1,387)		(1,199)		—		(2,942)
Commodity derivative assets subtotal	122		377		558		—		1,057		122		377		558		—		1,057
DPP consideration	—		401		—		—		401		—		401		—		—		401

91

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

	Exelon										Generation
As of March 31, 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	8,440		3,736		1,072		4,675		17,923		7,477		3,666		1,037		4,675		16,855
Liabilities
Commodity derivative liabilities
Economic hedges	(359)		(1,642)		(1,945)		—		(3,946)		(359)		(1,642)		(1,650)		—		(3,651)
Proprietary trading	—		(9)		(5)		—		(14)		—		(9)		(5)		—		(14)
Effect of netting and allocation of collateral(g)(h)	252		1,532		1,304		—		3,088		252		1,532		1,304		—		3,088
Commodity derivative liabilities subtotal	(107)		(119)		(646)		—		(872)		(107)		(119)		(351)		—		(577)
Deferred compensation obligation	—		(146)		—		—		(146)		—		(43)		—		—		(43)
Total liabilities	(107)		(265)		(646)		—		(1,018)		(107)		(162)		(351)		—		(620)
Total net assets	$	8,333	$	3,471	$	426	$	4,675	$	16,905	$	7,370	$	3,504	$	686	$	4,675	$	16,235

92

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

	Exelon										Generation
As of December 31, 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
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

__________    

93

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

(a)Exelon excludes cash of $1,273 million and $409 million at March 31, 2021 and December 31, 2020, respectively, and restricted cash of $93 million and $59 million at March 31, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $52 million and $53 million at March 31, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $608 million and $171 million at March 31, 2021 and December 31, 2020, respectively, and restricted cash of $29 million and $20 million at March 31, 2021 and December 31, 2020, respectively. 

(b)Includes $108 million and $116 million of cash received from outstanding repurchase agreements at March 31, 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 $(58) million and $(62) million as of March 31, 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 $2,049 million and $1,043 million at March 31, 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 $104 million and $181 million at March 31, 2021 and December 31, 2020, respectively, which include certain derivative assets that have notional amounts of $158 million and $104 million at March 31, 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. 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 March 31, 2021 and December 31, 2020, which resulted in unrealized gains of $95 million and $186 million within Other, net in Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income for the three months ended March 31, 2021 and for the year ended December 31, 2020, respectively.

(g)Collateral (received)/posted from counterparties, net of collateral paid to counterparties, totaled $(104) million, $145 million, and $105 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of March 31, 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)Of the collateral (received)/posted, $(148) million and $209 million represents variation margin on the exchanges as of March 31, 2021 and December 31, 2020, respectively.

As of March 31, 2021, Exelon and Generation have outstanding commitments to invest in private credit, private equity, and real estate investments of approximately $298 million, $239 million, and $344 million, respectively. These commitments will be funded by Generation’s existing NDT funds.

Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $61 million and $50 million as of March 31, 2021, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three months ended March 31, 2021.

94

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

ComEd, PECO, and BGE

	ComEd								PECO								BGE
As of March 31, 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)	$	300	$	—	$	—	$	300	$	7	$	—	$	—	$	7	$	—	$	—	$	—	$	—
Rabbi trust investments
Mutual funds	—		—		—		—		9		—		—		9		11		—		—		11
Life insurance contracts	—		—		—		—		—		13		—		13		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		9		13		—		22		11		—		—		11
Total assets	300		—		—		300		16		13		—		29		11		—		—		11
Liabilities
Deferred compensation obligation	—		(8)		—		(8)		—		(9)		—		(9)		—		(6)		—		(6)
Mark-to-market derivative liabilities(b)	—		—		(295)		(295)		—		—		—		—		—		—		—		—
Total liabilities	—		(8)		(295)		(303)		—		(9)		—		(9)		—		(6)		—		(6)
Total net assets (liabilities)	$	300	$	(8)	$	(295)	$	(3)	$	16	$	4	$	—	$	20	$	11	$	(6)	$	—	$	5

	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 $59 million and $83 million at March 31, 2021 and December 31, 2020, respectively, and restricted cash of $40 million and $37 million at March 31, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $43 million at both March 31, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $48 million and $18 million at March 31, 2021 and December 31, 2020, respectively. BGE excludes cash of $21 million and $24 million at March 31, 2021 and December 31, 2020, respectively, and restricted cash of $1 million at both March 31, 2021 and December 31, 2020.

(b)The Level 3 balance consists of the current and noncurrent liability of $31 million and $264 million, respectively, at March 31, 2021 and $33 million and $268 million, respectively, at December 31, 2020 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

95

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL, and ACE

	As of March 31, 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)	$	527	$	—	$	—	$	527	$	86	$	—	$	—	$	86
Rabbi trust investments
Cash equivalents	53		—		—		53		55		—		—		55
Mutual funds	15		—		—		15		14		—		—		14
Fixed income	—		10		—		10		—		11		—		11
Life insurance contracts	—		26		35		61		—		26		34		60
Rabbi trust investments subtotal	68		36		35		139		69		37		34		140
Total assets	595		36		35		666		155		37		34		226
Liabilities
Deferred compensation obligation	—		(16)		—		(16)		—		(17)		—		(17)
Total liabilities	—		(16)		—		(16)		—		(17)		—		(17)
Total net assets	$	595	$	20	$	35	$	650	$	155	$	20	$	34	$	209

	Pepco								DPL								ACE
As of March 31, 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)	$	128	$	—	$	—	$	128	$	50	$	—	$	—	$	50	$	349	$	—	$	—	$	349
Rabbi trust investments
Cash equivalents	53		—		—		53		—		—		—		—		—		—		—		—
Fixed income	—		2		—		2		—		—		—		—		—		—		—		—
Life insurance contracts	—		26		35		61		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	53		28		35		116		—		—		—		—		—		—		—		—
Total assets	181		28		35		244		50		—		—		50		349		—		—		349
Liabilities
Deferred compensation obligation	—		(2)		—		(2)		—		—		—		—		—		—		—		—
Total liabilities	—		(2)		—		(2)		—		—		—		—		—		—		—		—
Total net assets	$	181	$	26	$	35	$	242	$	50	$	—	$	—	$	50	$	349	$	—	$	—	$	349

96

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

	Pepco								DPL								ACE
As of December 31, 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 $72 million and $74 million at March 31, 2021 and December 31, 2020, respectively, and restricted cash of $5 million and none at March 31, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $9 million and $10 million at March 31, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $34 million and $30 million at March 31, 2021 and December 31, 2020, respectively, and restricted cash of $5 million and none at March 31, 2021 and December 31, 2020, respectively. DPL excludes cash of $14 million and $15 million at March 31, 2021 and December 31, 2020, respectively. ACE excludes cash of $17 million at both March 31, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $9 million and $10 million at March 31, 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 months ended March 31, 2021 and 2020:

	Exelon		Generation							ComEd			PHI and Pepco
Three months ended March 31, 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	(276)		1		(278)		(a)	(277)		—			1		—
Included in noncurrent payables to affiliates	—		1		—			1		—			—		(1)
Included in regulatory assets	7		—		—			—		6		(b)	—		1
Change in collateral	(57)		—		(57)			(57)		—			—		—
Purchases, sales, issuances and settlements
Purchases	109		—		109			109		—			—		—
Sales	1		—		1			1		—			—		—
Settlements	(20)		(20)		—			(20)		—			—		—
Transfers out of Level 3	2		—		2		(c)	2		—			—		—
Balance as of March 31, 2021	$	426	$	479	$	207		$	686	$	(295)		$	35	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2021	$	(147)	$	1	$	(149)		$	(148)	$	—		$	1	$	—

97

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

	Exelon		Generation							ComEd			PHI and Pepco
Three Months Ended March 31, 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	10		(1)		10		(a)	9		—			1		—
Included in noncurrent payables to affiliates	—		(1)		—			(1)		—			—		1
Included in regulatory assets	(14)		—		—			—		(13)		(b)	—		(1)
Change in collateral	1		—		1			1		—			—		—
Purchases, sales, issuances and settlements
Purchases	42		3		39			42		—			—		—
Sales	(22)		—		(22)			(22)		—			—		—
Settlements	(14)		(14)		—			(14)		—			—		—
Transfers into Level 3	2		—		2		(c)	2		—			—		—
Transfers out of Level 3	15		—		15		(c)	15		—			—		—
Balance as of March 31, 2020	$	1,088	$	498	$	862		$	1,360	$	(314)		$	42	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2020	$	187	$	(1)	$	187		$	186	$	—		$	1	$	—

__________

(a)Includes a reduction for the reclassification of $129 million and $177 million of realized losses due to the settlement of derivative contracts for the three months ended March 31, 2021 and 2020 respectively.

(b)Includes $2 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 March 31, 2021. Includes $23 million of decrease in fair value and an increase for realized losses due to settlements of $10 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 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 months ended March 31, 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 for the three months ended March 31, 2021	$	(116)	$	(162)	$	1	$	1	$	(116)	$	(162)	$	1	$	1
Total unrealized (losses) gains for the three months ended March 31, 2021	(65)		(84)		1		1		(65)		(84)		1		1

	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 gains (losses) for the three months ended March 31, 2020	$	72	$	(62)	$	1	$	(1)	$	72	$	(62)	$	(1)	$	1
Total unrealized gains (losses) gains for the three months ended March 31, 2020	205		(18)		1		(1)		205		(18)		(1)		1

98

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

Valuation Techniques Used to Determine Fair Value

Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 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.

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 March 31, 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)	$	90	$	245	Discounted Cash Flow	Forward power price	$1.35	-	$235	$32	$2.25	-	$163	$30
						Forward gas price	$1.42	-	$8.18	$2.59	$1.57	-	$7.88	$2.59
					Option Model	Volatility percentage	11%	-	116%	27%	11%	-	237%	32%
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)	$	12	$	23	Discounted Cash Flow	Forward power price	$9	-	$102	$30	$10	-	$106	$27
Mark-to-market derivatives (Exelon and ComEd)	$	(295)	$	(301)	Discounted Cash Flow	Forward heat rate(c)	8x	-	9x	8.85x	8x	-	9x	8.85x
						Marketability reserve	3%	-	8%	4.93%	3%	-	8%	4.93%
						Renewable factor	90%	-	123%	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 posted on level three positions of $105 million and $162 million as of March 31, 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.

99

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

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

14. Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 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 March 31, 2021:

Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments(a)	79		64		53		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 March 31, 2021, 27 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.

100

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

Commercial Commitments (All Registrants). The Registrants’ commercial commitments as of March 31, 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	$	1,639	$	1,156	$	483	$	—	$	—	$	—	$	—
Surety bonds(a)	1,077		919		158		—		—		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values(b)	29		—		3		4		6		5		11
Total commercial commitments	$	3,123	$	2,075	$	644	$	4	$	6	$	5	$	389
Generation
Letters of credit	$	1,623	$	1,141	$	482	$	—	$	—	$	—	$	—
Surety bonds(a)	932		794		138		—		—		—		—
Total commercial commitments	$	2,555	$	1,935	$	620	$	—	$	—	$	—	$	—
ComEd
Letters of credit	$	7	$	7	$	—	$	—	$	—	$	—	$	—
Surety bonds(a)	17		14		3		—		—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	224	$	21	$	3	$	—	$	—	$	—	$	200
PECO
Surety bonds(a)	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	180	$	2	$	—	$	—	$	—	$	—	$	178
BGE
Letters of credit	$	3	$	2	$	1	$	—	$	—	$	—	$	—
Surety bonds(a)	3		3		—		—		—		—		—
Total commercial commitments	$	6	$	5	$	1	$	—	$	—	$	—	$	—
PHI
Surety bonds(a)	$	23	$	20	$	3	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	29		—		3		4		6		5		11
Total commercial commitments	$	52	$	20	$	6	$	4	$	6	$	5	$	11
Pepco
Surety bonds(a)	$	14	$	14	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	10		—		1		1		2		2		4
Total commercial commitments	$	24	$	14	$	1	$	1	$	2	$	2	$	4
DPL
Surety bonds(a)	$	5	$	2	$	3	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	12		—		1		2		3		2		4
Total commercial commitments	$	17	$	2	$	4	$	2	$	3	$	2	$	4
ACE
Surety bonds(a)	$	4	$	4	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	7		—		1		1		1		1		3
Total commercial commitments	$	11	$	4	$	1	$	1	$	1	$	1	$	3

__________

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

101

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

(b)Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $73 million guaranteed by Exelon and PHI, of which $25 million, $30 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 8 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 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.

102

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

As of March 31, 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:

	March 31, 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	$	473	$	306	$	483	$	314
Generation	119		—		121		—
ComEd	281		280		293		293
PECO	23		21		23		21
BGE	6		5		2		—
PHI	44		—		44		—
Pepco	42		—		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 Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial

103

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

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 the National Park Service have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. 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 released its Interim ROD. The Interim ROD reflects an adaptive management approach which will require several

104

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

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.

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 March 31, 2021 and December 31, 2020, Exelon and Generation had recorded estimated liabilities of approximately $88 million and $89 million, respectively, in total for asbestos-related bodily injury claims. As of March 31, 2021, approximately $24 million of this amount related to 243 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 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.

105

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

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. Defendants' responsive pleading is due June 9, 2021.

•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. These three state cases were consolidated into a single action in October of 2020. In addition, on November 2, 2020, the Citizens Utility Board (CUB) filed a motion to intervene in the state 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 and have informed the court. The parties will report back to the court on the status of the mediation planning on April 29, 2021. A tentative date of June 1, 2021 has been set for oral argument on the pending motion to dismiss, but the parties have agreed to extend that date so long as a date to mediate has been selected by that time.

•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 have notified the court of their decision to mediate. Oral argument on the pending motion to dismiss and any discovery will be stayed pending mediation.

•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.

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.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

Various lawsuits have been filed against Generation during March and April of 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. During March and April of 2021, approximately 45 additional wrongful death lawsuits, naming multiple defendants including Generation, were filed by individual plaintiffs in different Texas counties, all arising out of the February weather events. 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. Generation has requested expedited treatment, but there is no timeline by which the MPSC must act. Based on the penalty provisions within the tariff that was in effect at the relevant time, Exelon and Generation recorded a liability of approximately $40 million as of March 31, 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.

15. Changes in Accumulated Other Comprehensive Income (Exelon)

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

Three Months Ended March 31, 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)		1		(1)
Amounts reclassified from AOCI	—		55		—		55
Net current-period OCI	—		53		1		54
Ending balance	$	(5)	$	(3,319)	$	(22)	$	(3,346)

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Changes in Accumulated Other Comprehensive Income

Three Months Ended March 31, 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)		(7)		(8)		(16)
Amounts reclassified from AOCI	—		37		—		37
Net current-period OCI	(1)		30		(8)		21
Ending balance	$	(3)	$	(3,135)	$	(35)	$	(3,173)

_________

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

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

	Three Months Ended March 31,
	2021		2020
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	1	$	4
Actuarial loss reclassified to periodic benefit cost	(19)		(17)
Pension and non-pension postretirement benefit plans valuation adjustment	—		3

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

At March 31, 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 March 31, 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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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 16 — Variable Interest Entities

	March 31, 2021								December 31, 2020
	Exelon		Generation		PHI (a)		ACE		Exelon		Generation		PHI (a)		ACE
Cash and cash equivalents	$	175	$	175	$	—	$	—	$	98	$	98	$	—	$	—
Restricted cash and cash equivalents	37		33		4		4		47		44		3		3
Accounts receivable
Customer	145		145		—		—		148		148		—		—
Other	35		35		—		—		36		36		—		—
Unamortized energy contract assets	22		22		—		—		22		22		—		—
Inventories, net
Materials and supplies	242		242		—		—		244		244		—		—
Assets held for sale(b)	—		—		—		—		101		101		—		—
Other current assets	448		443		5		—		674		669		5		—
Total current assets	1,104		1,095		9		4		1,370		1,362		8		3
Property, plant, and equipment, net	5,747		5,747		—		—		5,803		5,803		—		—
Nuclear decommissioning trust funds	3,089		3,089		—		—		3,007		3,007		—		—
Unamortized energy contract assets	243		243		—		—		249		249		—		—
Other noncurrent assets	47		38		9		9		52		42		10		10
Total noncurrent assets	9,126		9,117		9		9		9,111		9,101		10		10
Total assets(c)	$	10,230	$	10,212	$	18	$	13	$	10,481	$	10,463	$	18	$	13
Long-term debt due within one year	$	90	$	69	$	21	$	16	$	94	$	68	$	26	$	21
Accounts payable	95		95		—		—		81		81		—		—
Accrued expenses	67		67		—		—		70		70		—		—
Unamortized energy contract liabilities	3		3		—		—		4		4		—		—
Liabilities held for sale(b)	—		—		—		—		16		16		—		—
Other current liabilities	1		1		—		—		5		5		—		—
Total current liabilities	256		235		21		16		270		244		26		21
Long-term debt	861		861		—		—		889		889		—		—
Asset retirement obligations	2,347		2,347		—		—		2,318		2,318		—		—
Other noncurrent liabilities	116		116		—		—		129		129		—		—
Total noncurrent liabilities	3,324		3,324		—		—		3,336		3,336		—		—
Total liabilities(d)	$	3,580	$	3,559	$	21	$	16	$	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 $222 million and $249 million, Assets held for sale of $0 million and $9 million, and other unrestricted assets of $1 million and $1 million as of March 31, 2021 and December 31, 2020, respectively

(d)Exelon’s and Generation’s balances include liabilities with recourse of $2 million and $8 million as of March 31, 2021 and December 31, 2020, respectively.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 16 — Variable Interest Entities

As of March 31, 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

110

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 16 — 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 March 31, 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 March 31, 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:

	March 31, 2021						December 31, 2020
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	789	$	386	$	1,175	$	777	$	401	$	1,178
Total liabilities(a)	95		218		313		61		223		284
Exelon's ownership interest in VIE(a)	—		150		150		—		157		157
Other ownership interests in VIE(a)	694		18		712		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 March 31, 2021 and December 31, 2020.

111

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 16 — Variable Interest Entities

As of March 31, 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.

17. Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

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

	Operating revenues
	Exelon		Generation		PHI		DPL
Three Months Ended March 31, 2021
Operating lease income	$	4	$	3	$	1	$	1
Variable lease income	64		64		—		—
Three Months Ended March 31, 2020
Operating lease income	$	5	$	3	$	1	$	1
Variable lease income	69		69		—		—

	Taxes other than income taxes
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended March 31, 2021
Utility taxes(a)	$	217	$	24	$	59	$	35	$	25	$	74	$	67	$	6	$	1
Property	154		68		8		4		42		32		21		10		1
Payroll	61		28		7		4		5		7		2		1		—
Three Months Ended March 31, 2020
Utility taxes(a)	$	218	$	26	$	60	$	31	$	26	$	75	$	69	$	6	$	—
Property	150		69		7		4		39		31		21		9		1
Payroll	63		31		7		4		4		8		2		1		1

__________

(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.

112

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

	Other, net
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended March 31, 2021
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	291	$	291	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	203		203		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	(82)		(82)		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	(66)		(66)		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(167)		(167)		—		—		—		—		—		—		—
Decommissioning-related activities	179		179		—		—		—		—		—		—		—
AFUDC — Equity	28		—		4		6		7		11		9		1		1
Non-service net periodic benefit cost	20		—		—		—		—		—		—		—		—
Three Months Ended March 31, 2020
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	47	$	47	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	82		82		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	(932)		(932)		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	(706)		(706)		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	709		709		—		—		—		—		—		—		—
Decommissioning-related activities	(800)		(800)		—		—		—		—		—		—		—
AFUDC — Equity	23		—		6		3		5		9		6		1		2
Non-service net periodic benefit cost	10		—		—		—		—		—		—		—		—

__________

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

(b)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

113

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

Supplemental Cash Flow Information

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

	Depreciation, amortization and accretion
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended March 31, 2021
Property, plant, and equipment(a)	$	1,522	$	928	$	239	$	82	$	106	$	154	$	67	$	42	$	37
Amortization of regulatory assets(a)	160		—		53		4		46		56		35		11		10
Amortization of intangible assets, net(a)	15		12		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(b)	4		3		—		—		—		—		—		—		—
Nuclear fuel(c)	276		276		—		—		—		—		—		—		—
ARO accretion(d)	127		127		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	2,104	$	1,346	$	292	$	86	$	152	$	210	$	102	$	53	$	47
Three Months Ended March 31, 2020
Property, plant, and equipment(a)	$	856	$	290	$	228	$	79	$	97	$	144	$	64	$	38	$	34
Amortization of regulatory assets(a)	149		—		45		7		46		50		31		10		9
Amortization of intangible assets, net(a)	16		14		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(b)	2		2		—		—		—		—		—		—		—
Nuclear fuel(c)	231		231		—		—		—		—		—		—		—
ARO accretion(d)	124		124		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	1,378	$	661	$	273	$	86	$	143	$	194	$	95	$	48	$	43

__________

(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.

114

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

	Other non-cash operating activities
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended March 31, 2021
Pension and non-pension postretirement benefit costs	$	95	$	26	$	32	$	2	$	14	$	12	$	2	$	1	$	3
Allowance for credit losses	85		34		13		24		4		10		5		4		1
Other decommissioning-related activity(a)	(322)		(332)		—		—		—		—		—		—		—
Energy-related options(b)	17		17		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(c)	(129)		—		(54)		(10)		(18)		(46)		(26)		(9)		(11)
Long-term incentive plan	32		—		—		—		—		—		—		—		—
Amortization of operating ROU asset	37		21		—		—		7		7		1		3		1
AFUDC - Equity	(28)		—		(4)		(6)		(7)		(11)		(9)		(1)		(1)
Three Months Ended March 31, 2020
Pension and non-pension postretirement benefit costs	$	98	$	27	$	28	$	1	$	15	$	17	$	3	$	1	$	3
Allowance for credit losses	45		4		7		17		7		10		4		3		3
Other decommissioning-related activity(a)	128		128		—		—		—		—		—		—		—
Energy-related options(b)	6		6		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(d)	(71)		—		(17)		—		(35)		(19)		(15)		(4)		—
Long-term incentive plan	(7)		—		—		—		—		—		—		—		—
Amortization of operating ROU asset	51		35		—		—		8		5		2		2		1
AFUDC - Equity	(23)		—		(6)		(3)		(5)		(9)		(6)		(1)		(2)

__________

(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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

(c)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency, 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)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution and energy efficiency formula rates. For BGE, Pepco, and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms. See Note 3 — Regulatory Matters for additional information.

115

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

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

	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2021
Cash and cash equivalents	$	1,908	$	721	$	86	$	48	$	21	$	558	$	134	$	64	$	353
Restricted cash and cash equivalents	374		41		270		7		1		37		33		—		4
Restricted cash included in other long-term assets	52		—		43		—		—		9		—		—		9
Total cash, restricted cash, and cash equivalents	$	2,334	$	762	$	399	$	55	$	22	$	604	$	167	$	64	$	366
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
March 31, 2020
Cash and cash equivalents	$	1,457	$	821	$	514	$	31	$	11	$	49	$	18	$	7	$	8
Restricted cash and cash equivalents	414		150		211		7		1		37		33		—		3
Restricted cash included in other long-term assets	121		—		108		—		—		12		—		—		12
Total cash, restricted cash, and cash equivalents	$	1,992	$	971	$	833	$	38	$	12	$	98	$	51	$	7	$	23
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.

116

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

Supplemental Balance Sheet Information

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

	Accrued expenses
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2021
Compensation-related accruals(a)	$	581	$	210	$	91	$	42	$	49	$	73	$	26	$	15	$	12
Taxes accrued	540		279		70		18		50		108		92		10		12
Interest accrued	424		76		65		36		41		79		37		20		20
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.

18. Related Party Transactions (All Registrants)

Operating revenues from affiliates

Generation

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

	Three Months Ended March 31,
	2021		2020
Operating revenues from affiliates:
ComEd(a)(b)	$	78	$	90
PECO(c)	42		37
BGE(d)	72		99
PHI	100		103
Pepco(e)	75		79
DPL(f)	21		22
ACE(g)	4		2
Other	3		1
Total operating revenues from affiliates (Generation)	$	295	$	330

__________

(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 months ended March 31, 2021, ComEd’s Purchased power from Generation of $84 million is recorded as Operating revenues from ComEd of $78 million and as Purchased power and fuel from ComEd of $6 million at Generation. For the three months ended March 31, 2020, ComEd’s Purchased power from Generation of $97 million is recorded as Operating revenues from ComEd of $90 million and as Purchased power and fuel from ComEd of $7 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.

117

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 18 — 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.

Operating and maintenance expense from affiliates

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

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

	Operating and maintenance from affiliates				Capitalized costs
	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2021		2020
Exelon
BSC					$	124	$	113
PHISCO					17		14
Generation
BSC	$	144	$	140	10		11
ComEd
BSC	71		72		45		42
PECO
BSC	39		37		17		16
BGE
BSC	43		41		20		28
PHI
BSC	39		37		32		16
PHISCO	—		—		17		14
Pepco
BSC	22		21		13		6
PHISCO	30		30		7		6
DPL
BSC	14		13		10		5
PHISCO	25		24		5		4
ACE
BSC	12		11		8		4
PHISCO	22		22		5		4

118

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 18 — Related Party Transactions

Current Receivables from/Payables to affiliates

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

March 31, 2021

	Receivables from affiliates:
Payables to affiliates:	Generation			ComEd		PECO		BGE		Pepco		DPL		ACE		BSC		PHISCO		Other		Total
Generation				$	17	$	—	$	—	$	—	$	—	$	—	$	84	$	—	$	24	$	125
ComEd	$	50	(a)			—		—		—		—		—		49		—		5		104
PECO	15			—				—		—		—		—		24		—		7		46
BGE	11			1		—				—		—		—		30		—		1		43
PHI	—			1		—		—		—		—		—		7		—		10		18
Pepco	12			1		—		—				—		—		16		14		1		44
DPL	2			—		—		—		—				—		11		11		—		24
ACE	8			—		—		—		—		—				8		10		1		27
Other	8			1		—		—		—		—		1		—		—				10
Total	$	106		$	21	$	—	$	—	$	—	$	—	$	1	$	229	$	35	$	49	$	441

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 March 31, 2021 and December 31, 2020, Generation had a contract liability with ComEd for $24 million and $50 million, respectively, that was included in Other current liabilities on Generation’s Consolidated Balance Sheets. At March 31, 2021 and December 31, 2020, ComEd had a Current Payable to Generation of $26 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.

119

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 18 — 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:

	March 31, 2021		December 31, 2020
ComEd	$	2,375	$	2,541
PECO	490		475

Long-term debt to financing trusts

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

	March 31, 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.

19. 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 FERC and the IRS in the third quarter of 2021, the NRC in the fourth quarter of 2021, and have requested a decision from the NYPSC before the end of 2021 but 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 (Loss) attributable to common shareholders by Registrant for the three months ended March 31, 2021 compared to the same period in 2020. For additional information regarding the financial results for the three months ended March 31, 2021 and 2020 see the discussions of Results of Operations by Registrant.

	Three Months Ended March 31,				Favorable (unfavorable) variance
	2021		2020
Exelon	$	(289)	$	582	$	(871)
Generation	(793)		45		(838)
ComEd	197		168		29
PECO	167		140		27
BGE	209		181		28
PHI	128		108		20
Pepco	59		52		7
DPL	56		45		11
ACE	14		13		1
Other(a)	(197)		(60)		(137)

__________

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

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020. Net income attributable to common shareholders decreased by $871 million and diluted loss per average common share decreased to $(0.30) in 2021 from $0.60 in 2020 primarily due to:

•Impacts of the February 2021 extreme cold weather event;

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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; and

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

The decreases were partially offset by:

•Lower unrealized losses and higher realized gains on NDT funds;

•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

•Favorable weather conditions at PECO, DPL and ACE.

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

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The following table provides a reconciliation between net income (loss) attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings (loss) for the three months ended March 31, 2021 compared to the same period in 2020.

	Three Months Ended March 31,
	2021				2020
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net Income (Loss) Attributable to Common Shareholders	$	(289)	$	(0.30)	$	582	$	0.60
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $46 and $32, respectively)	(135)		(0.14)		(94)		(0.10)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $40 and $405, respectively)(a)	43		0.04		485		0.50
Asset Impairments (net of taxes of $1)	—		—		2		—
Plant Retirements and Divestitures (net of taxes of $103 and $4, respectively)(b)	310		0.32		13		0.01
Cost Management Program (net of taxes of $0 and $3, respectively)(c)	1		—		9		0.01
Change in Environmental Liabilities (net of taxes of $1)	2		—		—		—
COVID-19 Direct Costs (net of taxes of $4)(d)	10		0.01		—		—
Acquisition Related Costs (net of tax of $2)(e)	6		0.01		—		—
ERP System Implementation Costs (net of taxes of $1)(f)	5		0.01		—		—
Planned Separation Costs (net of taxes of $2)(g)	7		0.01		—		—
Income Tax-Related Adjustments (entire amount represents tax expense)	(2)		—		(2)		—
Noncontrolling Interests (net of taxes of $6 and $30, respectively)(h)	(17)		(0.02)		(144)		(0.15)
Adjusted (non-GAAP) Operating Earnings (Loss)	$	(60)	$	(0.06)	$	851	$	0.87

__________

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income (Loss) and Adjusted (non-GAAP) Operating Earnings (Loss) 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 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 losses related to NDT fund investments were 48.0% and 45.5% for the three months ended March 31, 2021 and 2020, respectively.

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

(b)In 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.

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

(d)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.

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

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

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

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

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Significant 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 FERC and the IRS in the third quarter of 2021, the NRC in the fourth quarter of 2021, and have requested a decision from the NYPSC before the end of 2021 but cannot predict if the applications will be approved as filed.

In connection with the planned separation, Exelon incurred transaction costs of approximately $9 million on a pre-tax basis in the first quarter of 2021, which are excluded from Adjusted (non-GAAP) Operating Earnings. The transaction costs are primarily comprised of third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation as well as 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 19 — 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

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.

The estimated impact to Exelon’s and Generation’s Net income for the first quarter of 2021 arising from these market and weather conditions was a reduction of approximately $880 million. The first quarter 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 14 — 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.

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

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. Completion of the transaction is expected in the second half of 2021.

As a result, in the second quarter of 2021, Exelon and Generation will reclassify these assets and liabilities as held for sale and expect to record an impairment loss in a range of $135 million to $150 million on a pre-tax basis, which will be excluded from Exelon’s and Generation’s Adjusted (non-GAAP) Operating Earnings. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

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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
BGE - Maryland	May 15, 2020 (amended September 11, 2020)	Electric	137		81		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	91		21		9.65	%

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	$	51	7.36	%	Fourth quarter of 2021
PECO - Pennsylvania	March 30, 2021	Electric	246		10.95	%	Fourth quarter of 2021
PECO - Pennsylvania	September 30, 2020	Natural Gas	69		10.95	%	Second quarter of 2021
Pepco - District of Columbia	May 30, 2019 (amended June 1, 2020)	Electric	136		9.7	%	Second quarter of 2021
Pepco - Maryland	October 26, 2020 (amended March 31, 2021)	Electric	104		10.2	%	Second quarter of 2021
DPL - Delaware	March 6, 2020 (amended February 2, 2021)	Electric	23		10.3	%	Third quarter of 2021
ACE - New Jersey	December 9, 2020 (amended February 26, 2021)	Electric	67		10.3	%	Fourth quarter of 2021

Transmission Formula Rates

The following total increases were included in ComEd's 2021 electric transmission formula rate update. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Registrant	Initial Revenue Requirement Increase		Annual Reconciliation Increase		Total Revenue Requirement Increase		Allowed Return on Rate Base		Allowed ROE
ComEd	$	33	$	12	$	45	8.20	%	11.50	%

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Other Key Business Drivers and Management Strategies

The following discussion of other key business driver and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the Registrants' combined 2020 Form 10-K and Note 14 — Commitments and Contingencies to the Consolidated Financial Statements in this report for additional information on various environmental matters.

Power Markets

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 request briefs on the matter, including alternative approaches to mitigation in the capacity market. FERC clarified that the capacity auction for delivery year 2022/2023 (scheduled for May 2021) should go forward as scheduled under the current rules. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation.

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 March 31, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% 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 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.

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

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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 Registrants’ existing transmission rates include the ROE incentive adder. Exelon plans to provide comments to FERC on this matter which are due by May 26, 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 2020 Form 10-K for additional information regarding the Utility Registrants’ transmission formula rates and regulatory proceedings at the FERC.

Employees

In April 2021, 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 March 31, 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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Generation

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 March 31,				Favorable (Unfavorable) Variance
	2021		2020
Operating revenues	$	5,559	$	4,733	$	826
Purchased power and fuel expense	4,610		2,704		(1,906)
Revenues net of purchased power and fuel expense	949		2,029		(1,080)
Other operating expenses
Operating and maintenance	1,001		1,263		262
Depreciation and amortization	940		304		(636)
Taxes other than income taxes	121		129		8
Total other operating expenses	2,062		1,696		(366)
Gain on sales of assets and businesses	71		—		71
Operating (loss) income	(1,042)		333		(1,375)
Other income and (deductions)
Interest expense, net	(72)		(109)		37
Other, net	167		(771)		938
Total other income and (deductions)	95		(880)		975
Loss before income taxes	(947)		(547)		(400)
Income taxes	(179)		(389)		(210)
Equity in losses of unconsolidated affiliates	(1)		(3)		2
Net loss	(769)		(161)		(608)
Net income (loss) attributable to noncontrolling interests	24		(206)		230
Net (loss) income attributable to membership interest	$	(793)	$	45	$	(838)

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020. Net income attributable to membership interest decreased by $838 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; and

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

The decreases were partially offset by:

•Lower unrealized losses and higher realized gains on NDT funds.

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-

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Generation

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 and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.

For the three months ended March 31, 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 March 31,				Variance		% Change
	2021		2020
Mid-Atlantic(a)	$	567	$	567	$	—	—	%
Midwest(b)	702		727		(25)		(3.4)	%
New York	242		193		49		25.4	%
ERCOT	(1,184)		80		(1,264)		(1,580.0)	%
Other Power Regions	217		158		59		37.3	%
Total electric revenues net of purchased power and fuel expense	544		1,725		(1,181)		(68.5)	%
Mark-to-market gains	175		131		44		33.6	%
Other	230		173		57		32.9	%
Total revenue net of purchased power and fuel expense	$	949	$	2,029	$	(1,080)	(53.2)	%

__________

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

(b)Includes results of transactions with ComEd.

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Generation

Generation’s supply sources by region are summarized below:

	Three Months Ended March 31,		Variance	% Change
Supply Source (GWhs)	2021	2020
Nuclear Generation(a)
Mid-Atlantic	13,254	12,784	470	3.7	%
Midwest	23,155	23,598	(443)	(1.9)	%
New York	7,057	6,173	884	14.3	%
Total Nuclear Generation	43,466	42,555	911	2.1	%
Fossil and Renewables
Mid-Atlantic	662	853	(191)	(22.4)	%
Midwest	323	388	(65)	(16.8)	%
New York	1	1	—	—	%
ERCOT	2,783	3,012	(229)	(7.6)	%
Other Power Regions	2,964	3,508	(544)	(15.5)	%
Total Fossil and Renewables	6,733	7,762	(1,029)	(13.3)	%
Purchased Power
Mid-Atlantic	4,483	5,943	(1,460)	(24.6)	%
Midwest	179	288	(109)	(37.8)	%
ERCOT	772	991	(219)	(22.1)	%
Other Power Regions	12,834	12,167	667	5.5	%
Total Purchased Power	18,268	19,389	(1,121)	(5.8)	%
Total Supply/Sales by Region
Mid-Atlantic(b)	18,399	19,580	(1,181)	(6.0)	%
Midwest(b)	23,657	24,274	(617)	(2.5)	%
New York	7,058	6,174	884	14.3	%
ERCOT	3,555	4,003	(448)	(11.2)	%
Other Power Regions	15,798	15,675	123	0.8	%
Total Supply/Sales by Region	68,467	69,706	(1,239)	(1.8)	%

__________

(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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Generation

For the three months ended March 31, 2021 compared to 2020, changes in RNF by region were as follows:

	(Decrease)/ Increase		2021 vs. 2020
			Description
Mid-Atlantic	$	—	• increased capacity revenue, offset by • decreased load served
Midwest	(25)		• decreased load served • decreased total ISO sales due to decreased generation
New York	49		• decreased nuclear outage days • increased ZEC revenues due to decreased nuclear outage days
ERCOT	(1,264)		• higher energy procurement costs due to the February 2021 extreme cold weather event, as well as the impact of ERCOT market participant defaults
Other Power Regions	59		• increase in newly contracted load • higher portfolio optimization • higher realized energy prices, partially offset by • decreased capacity revenue
Mark-to-market(a)	44		• gains on economic hedging activities of $131 million in 2020 compared to gains of $175 million in 2021
Other	57		• higher natural gas portfolio optimization partially offset by penalties associated with operational flow orders and curtailments as a result of the February 2021 extreme cold weather event, partially offset by • increase in accelerated nuclear fuel amortization associated with announced early plant retirements • decreased revenue related to the energy efficiency business
Total	$	(1,080)

__________

(a)See Note 11 — 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 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

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Generation

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 March 31,
	2021		2020
Nuclear fleet capacity factor	95.3	%	93.9	%
Refueling outage days	84		94
Non-refueling outage days	3		11

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

	Three Months Ended March 31, 2021
	Increase (Decrease)
Credit loss expense	$	47
Labor, other benefits, contracting, and materials(a)	(27)
Nuclear refueling outage costs, including the co-owned Salem plants	(51)
Plant retirements and divestitures	(221)
Other	(10)
Total decrease	$	(262)

__________ 

(a)Primarily reflects decreased contracting costs.

Depreciation and amortization expense for the three months ended March 31, 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.

Gain on sales of assets and businesses for the three months ended March 31, 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 three months ended March 31, 2021 compared to the same period in 2020 decreased primarily due to decreases in interest rates.

Other, net for the three months ended March 31, 2021 compared to the same period in 2020 increased due to activity described in the table below:

	Three Months Ended March 31,
	2021		2020
Net unrealized losses on NDT funds(a)	$	(66)	$	(706)
Net realized gains on sale of NDT funds(a)	185		55
Interest and dividend income on NDT funds(a)	18		27
Contractual elimination of income tax expense(b)	42		(176)
Net unrealized losses from equity investments(c)	(23)		—
Other	11		29
Total other, net	$	167	$	(771)

__________ 

(a)Unrealized 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 losses on equity investments that became publicly traded entities in the fourth quarter of 2020 and the first quarter of 2021.

132

Generation

Effective income tax rates were 18.9% and 71.1% for the three months ended March 31, 2021 and 2020, respectively. See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information

Net income attributable to noncontrolling interests for the three months ended March 31, 2021 compared to the same period in 2020 increased primarily due to higher net gains on NDT fund investments for CENG.

133

ComEd

Results of Operations — ComEd

	Three Months Ended March 31,				Favorable (Unfavorable) Variance
	2021		2020
Operating revenues	$	1,535	$	1,439	$	96
Operating expenses
Purchased power expense	527		486		(41)
Operating and maintenance	316		317		1
Depreciation and amortization	292		273		(19)
Taxes other than income taxes	75		75		—
Total operating expenses	1,210		1,151		(59)
Operating income	325		288		37
Other income and (deductions)
Interest expense, net	(96)		(94)		(2)
Other, net	7		10		(3)
Total other income and (deductions)	(89)		(84)		(5)
Income before income taxes	236		204		32
Income taxes	39		36		(3)
Net income	$	197	$	168	$	29

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020. Net income increased $29 million as compared to the same period in 2020, primarily due to increased 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).

The changes in Operating revenues consisted of the following:

	Three Months Ended March 31, 2021
	Increase
Distribution	$	21
Transmission	2
Energy efficiency	12
Other	12
	47
Regulatory required programs	49
Total increase	$	96

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 in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased for the three months ended March 31, 2021 as compared to the same period in 2020, due to the impact of higher rate base and higher allowed ROE due to an increase in treasury rates.

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.

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ComEd

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 months ended March 31, 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. The increase in Other revenue for the three months ended March 31, 2021 as compared to the same period in 2020, 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 acts as the billing agent and therefore 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 $41 million for the three months ended March 31, 2021 compared to the same period in 2020, respectively, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

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

	Three Months Ended March 31, 2021
	(Decrease) Increase
Storm-related costs	$	(9)
Labor, other benefits, contracting and materials	8
Pension and non-pension postretirement benefits expense	1
Other	(6)
	(6)
Regulatory required programs(a)	5
Total decrease	$	(1)

__________

(a)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.

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ComEd

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

	Three Months Ended March 31, 2021
	Increase
Depreciation and amortization(a)	$	11
Regulatory asset amortization(b)	8
Total increase	$	19

__________

(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 16.5% and 17.6% for the three months ended March 31, 2021 and 2020, respectively. See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

136

PECO

Results of Operations — PECO

	Three Months Ended March 31,				Favorable (Unfavorable) Variance
	2021		2020
Operating revenues	$	889	$	813	$	76
Operating expenses
Purchased power and fuel expense	316		283		(33)
Operating and maintenance	234		217		(17)
Depreciation and amortization	86		86		—
Taxes other than income taxes	43		39		(4)
Total operating expenses	679		625		(54)
Operating income	210		188		22
Other income and (deductions)
Interest expense, net	(38)		(36)		(2)
Other, net	5		3		2
Total other income and (deductions)	(33)		(33)		—
Income before income taxes	177		155		22
Income taxes	10		15		5
Net income	$	167	$	140	$	27

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020. Net income increased by $27 million primarily due to favorable weather conditions and volume.

The changes in Operating revenues consisted of the following:

	Three Months Ended March 31, 2021
	Increase (Decrease)
	Electric		Gas		Total
Weather	$	21	$	16	$	37
Volume	12		2		14
Pricing	(6)		(1)		(7)
Transmission	1		—		1
Other	(2)		—		(2)
	26		17		43
Regulatory required programs	31		2		33
Total increase	$	57	$	19	$	76

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 March 31, 2021 compared to the same period in 2020, Operating 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-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in

137

PECO

PECO’s service territory for the three months ended March 31, 2021 compared to the same period in 2020 and normal weather consisted of the following:

Heating and Cooling Degree-Days			Normal	% Change
	2021	2020		From 2020		2021 vs. Normal
Three Months Ended March 31,
Heating Degree-Days	2,302	1,989	2,418	15.7	%	(4.8)	%
Cooling Degree-Days	5	—	1	n/a		400.0	%

Volume. Electric volume, exclusive of the effects of weather, for the three months ended March 31, 2021, compared to the same period in 2020, increased on a net basis due to an increase in usage for residential customers further increased by customer growth. Natural gas volume for the three months ended March 31, compared to the same period in 2020, remained relatively consistent.

Electric Retail Deliveries to Customers (in GWhs)	Three Months Ended March 31,		% Change		Weather - Normal % Change(b)
	2021	2020
Residential	3,767	3,254	15.8	%	6.2	%
Small commercial & industrial	1,881	1,905	(1.3)	%	(5.1)	%
Large commercial & industrial	3,272	3,421	(4.4)	%	(5.0)	%
Public authorities & electric railroads	149	151	(1.3)	%	(1.4)	%
Total electric retail deliveries(a)	9,069	8,731	3.9	%	(0.6)	%

	As of March 31,
Number of Electric Customers	2021	2020
Residential	1,512,255	1,499,019
Small commercial & industrial	154,637	154,056
Large commercial & industrial	3,109	3,093
Public authorities & electric railroads	10,237	10,096
Total	1,680,238	1,666,264

__________

(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 March 31,		% Change		Weather - Normal % Change(b)
	2021	2020
Residential	20,674	17,282	19.6	%	2.8	%
Small commercial & industrial	10,170	8,809	15.5	%	(0.2)	%
Large commercial & industrial	7	9	(22.2)	%	(0.6)	%
Transportation	7,650	7,135	7.2	%	0.4	%
Total natural gas retail deliveries(a)	38,501	33,235	15.8	%	1.5	%

	As of March 31,
Number of Natural Gas Customers	2021	2020
Residential	493,857	489,063
Small commercial & industrial	44,604	44,509
Large commercial & industrial	5	5
Transportation	685	727
Total	539,151	534,304

__________

(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.

138

PECO

Pricing for the three months ended March 31, 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 acts as the billing agent and therefore 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 primarily includes revenue related to late payment charges. Other revenues for the three months ended March 31, 2021 compared to the same period in 2020, decreased as PECO ceased new late fees for all customers and restored service to customers upon request who were disconnected in the last twelve months beginning March of 2020.

See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

The increase of $33 million for the three months ended March 31, 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 March 31, 2021
	Increase (Decrease)
Labor, other benefits, contracting and materials	10
Credit loss expense	7
Storm-related costs	6
BSC costs	3
Regulatory Required Programs	(2)
Other	(7)
Total increase	$	17

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

	Three Months Ended March 31, 2021
	Increase (Decrease)
Depreciation and amortization(a)	$	3
Regulatory asset amortization	(3)
Total increase	$	—

__________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Interest expense, net increased $2 million for the three months ended March 31, 2021 compared to the same period in 2020, respectively, primarily due to the issuance of debt in June 2020 and March 2021.

139

PECO

Effective income tax rates were 5.6% and 9.7% for the three months ended March 31, 2021 and 2020, respectively. See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

140

BGE

Results of Operations — BGE

	Three Months Ended March 31,				Favorable (Unfavorable) Variance
	2021		2020
Operating revenues	$	974	$	937	$	37
Operating expenses
Purchased power and fuel expense	331		288		(43)
Operating and maintenance	197		188		(9)
Depreciation and amortization	152		143		(9)
Taxes other than income taxes	72		69		(3)
Total operating expenses	752		688		(64)
Operating income	222		249		(27)
Other income and (deductions)
Interest expense, net	(34)		(32)		(2)
Other, net	8		5		3
Total other income and (deductions)	(26)		(27)		1
Income before income taxes	196		222		(26)
Income taxes	(13)		41		54
Net income	$	209	$	181	$	28

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020. Net income increased by $28 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 March 31, 2021
	(Decrease) Increase
	Electric		Gas		Total
Distribution	$	—	$	(1)	$	(1)
Transmission	3		—		3
Other	(7)		(1)		(8)
	(4)		(2)		(6)
Regulatory required programs	24		19		43
Total increase	$	20	$	17	$	37

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

	As of March 31,
Number of Electric Customers	2021	2020
Residential	1,192,470	1,181,329
Small commercial & industrial	114,819	114,697
Large commercial & industrial	12,505	12,376
Public authorities & electric railroads	266	265
Total	1,320,060	1,308,667

141

BGE

	As of March 31,
Number of Natural Gas Customers	2021	2020
Residential	648,824	641,608
Small commercial & industrial	38,318	38,381
Large commercial & industrial	6,120	6,078
Total	693,262	686,067

Distribution Revenue remained relatively consistent for the three months ended March 31, 2021, compared to the same period in 2020.

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.

Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees.

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 acts as the billing agent and therefore 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 $43 million for the three months ended March 31, 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.

142

BGE

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

	Three Months Ended March 31, 2021
	Increase (Decrease)
Storm-related costs	$	6
BSC costs	2
Credit loss expense	(2)
Other	3
Total increase	$	9

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

	Three Months Ended March 31, 2021
	Increase
Depreciation and amortization(a)	$	9
Total increase	$	9

_________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were (6.6)% and 18.5% for the three months ended March 31, 2021 and 2020, respectively. The change is primarily due to the multi-year plan which resulted in the acceleration of certain income tax benefits. 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 and Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

143

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 months ended March 31, 2021 compared to the same period in 2020. See the Results of Operations for Pepco, DPL, and ACE for additional information.

	Three Months Ended March 31,				Favorable Variance
	2021		2020
PHI	$	128	$	108	$	20
Pepco	59		52		7
DPL	56		45		11
ACE	14		13		1
Other(a)	(1)		(2)		1

_________

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

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020. Net Income increased by $20 million primarily due to favorable weather conditions in DPL's Delaware and ACE's service territories and higher electric distribution rates at DPL.

144

Pepco

Results of Operations — Pepco

	Three Months Ended March 31,				Favorable (Unfavorable) Variance
	2021		2020
Operating revenues	$	553	$	544	$	9
Operating expenses
Purchased power expense	166		164		(2)
Operating and maintenance	108		111		3
Depreciation and amortization	102		95		(7)
Taxes other than income taxes	90		92		2
Total operating expenses	466		462		(4)
Operating income	87		82		5
Other income and (deductions)
Interest expense, net	(34)		(34)		—
Other, net	12		9		3
Total other income and (deductions)	(22)		(25)		3
Income before income taxes	65		57		8
Income taxes	6		5		(1)
Net income	$	59	$	52	$	7

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020. Net income remained relatively consistent.

The changes in Operating revenues consisted of the following:

	Three Months Ended March 31, 2021
	Increase (Decrease)
Distribution	$	3
Transmission	(3)
Other	4
	4
Regulatory required programs	5
Total increase	$	9

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.

	As of March 31,
Number of Electric Customers	2021	2020
Residential	835,415	820,283
Small commercial & industrial	53,738	54,304
Large commercial & industrial	22,492	22,248
Public authorities & electric railroads	174	169
Total	911,819	897,004

Distribution Revenue increased for the three months ended March 31, 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.

145

Pepco

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 acts as the billing agent and therefore 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 increase of $2 million for the three months ended March 31, 2021 compared to the same period in 2020, 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 March 31, 2021
	(Decrease) Increase
Labor, other benefits, contracting and materials	$	(6)
Pension and non-pension postretirement benefits expense	(1)
BSC and PHISCO costs	1
Credit loss expense	2
Other	1
Total decrease	$	(3)

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

	Three Months Ended March 31, 2021
	Increase (Decrease)
Depreciation and amortization(a)	$	4
Regulatory asset amortization	(1)
Regulatory required programs	4
Total increase	$	7

_________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were 9.2% and 8.8% for the three months ended March 31, 2021 and 2020, respectively. See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

146

DPL

Results of Operations — DPL

	Three Months Ended March 31,				Favorable (Unfavorable) Variance
	2021		2020
Operating revenues	$	382	$	350	$	32
Operating expenses
Purchased power and fuel expense	156		141		(15)
Operating and maintenance	83		79		(4)
Depreciation and amortization	53		48		(5)
Taxes other than income taxes	17		16		(1)
Total operating expenses	309		284		(25)
Operating income	73		66		7
Other income and (deductions)
Interest expense, net	(15)		(16)		1
Other, net	3		2		1
Total other income and (deductions)	(12)		(14)		2
Income before income taxes	61		52		9
Income taxes	5		7		2
Net income	$	56	$	45	$	11

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020. Net income increased by $11 million primarily due to favorable weather conditions in DPL's Delaware electric and natural gas service territories and higher electric distribution rates.

The changes in Operating revenues consisted of the following:

	Three Months Ended March 31, 2021
	Increase (Decrease)
	Electric		Gas		Total
Weather	$	4	$	5	$	9
Volume	—		1		1
Distribution	5		—		5
Other	1		(1)		—
	10		5		15
Regulatory required programs	15		2		17
Total increase	$	25	$	7	$	32

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended March 31, 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.

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DPL

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 months ended March 31, 2021 compared to same period in 2020 and normal weather consisted of the following:

Delaware Electric Service Territory				% Change
Three Months Ended March 31,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	2,358	2,003	2,493	17.7	%	(5.4)	%
Cooling Degree-Days	3	—	—	n/a		n/a

Delaware Natural Gas Service Territory				% Change
Three Months Ended March 31,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	2,358	2,003	2,497	17.7	%	(5.6)	%

Volume, exclusive of the effects of weather, remained relatively consistent for the three months ended March 31, 2021 compared to the same period in 2020.

Electric Retail Deliveries to Delaware Customers (in GWhs)	Three Months Ended March 31,		% Change		Weather - Normal % Change(b)
	2021	2020
Residential	854	743	14.9	%	4.5	%
Small commercial & industrial	342	296	15.5	%	10.5	%
Large commercial & industrial	689	823	(16.3)	%	(17.2)	%
Public authorities & electric railroads	9	8	12.5	%	7.7	%
Total electric retail deliveries(a)	1,894	1,870	1.3	%	(3.6)	%

	As of March 31,
Number of Total Electric Customers (Maryland and Delaware)	2021	2020
Residential	473,917	469,082
Small commercial & industrial	62,647	61,769
Large commercial & industrial	1,208	1,414
Public authorities & electric railroads	608	612
Total	538,380	532,877

_________

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

(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.

Natural Gas Retail Deliveries to Delaware Customers (in mmcf)	Three Months Ended March 31,		% Change		Weather - Normal % Change(b)
	2021	2020
Residential	4,394	3,647	20.5	%	2.6	%
Small commercial & industrial	1,868	1,671	11.8	%	(3.9)	%
Large commercial & industrial	457	452	1.1	%	1.1	%
Transportation	2,224	2,108	5.5	%	(0.9)	%
Total natural gas deliveries(a)	8,943	7,878	13.5	%	0.2	%

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DPL

	As of March 31,
Number of Delaware Natural Gas Customers	2021	2020
Residential	127,522	126,209
Small commercial & industrial	10,043	10,004
Large commercial & industrial	19	17
Transportation	160	159
Total	137,744	136,389

__________

(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 months ended March 31, 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, 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.

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 or natural gas from competitive suppliers, DPL acts as the billing agent and therefore 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 DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up and natural gas costs without mark-up.

See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

The increase of $15 million for the three months ended March 31, 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.

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

	Three Months Ended March 31, 2021
	Increase (Decrease)
Labor, other benefits, contracting and materials	$	2
BSC and PHISCO costs	2
Credit loss expense	1
Pension and non-pension postretirement benefits expense	(1)
Total increase	$	4

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DPL

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

	Three Months Ended March 31, 2021
	Increase
Depreciation and amortization(a)	$	3
Regulatory required programs	2
Total increase	$	5

_________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were 8.2% and 13.5% for the three months ended March 31, 2021 and 2020, respectively. See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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ACE

Results of Operations — ACE

	Three Months Ended March 31,				Favorable (Unfavorable) Variance
	2021		2020
Operating revenues	$	310	$	276	$	34
Operating expenses
Purchased power expense	157		128		(29)
Operating and maintenance	76		78		2
Depreciation and amortization	47		43		(4)
Taxes other than income taxes	2		2		—
Total operating expenses	282		251		(31)
Gain on sale of assets	—		2		(2)
Operating income	28		27		1
Other income and (deductions)
Interest expense, net	(15)		(15)		—
Other, net	1		2		(1)
Total other income and (deductions)	(14)		(13)		(1)
Income before income taxes	14		14		—
Income taxes	—		1		1
Net income	$	14	$	13	$	1

Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020. Net income remained relatively consistent.

The changes in Operating revenues consisted of the following:

	Three Months Ended March 31, 2021
	Increase (Decrease)
Weather	$	4
Volume	2
Distribution	(1)
Other	1
	6
Regulatory required programs	28
Total increase	$	34

Weather. The demand for electricity is affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. There was an increase related to weather for the three months ended March 31, 2021 compared to same period in 2020 due to the impact of favorable weather conditions in ACE's service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the three months ended March 31, 2021 compared to same period in 2020 and normal weather consisted of the following:

Heating and Cooling Degree-Days				% Change
Three Months Ended March 31,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	2,348	1,948	2,469	20.5	%	(4.9)	%
Cooling Degree-Days	4	—	—	n/a		n/a

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ACE

Volume, exclusive of the effects of weather, increased for the three months ended March 31, 2021 compared to the same period in 2020, primarily due to residential customer growth and usage, partially offset by lower commercial and industrial usage.

Electric Retail Deliveries to Customers (in GWhs)	Three Months Ended March 31,		% Change		Weather - Normal % Change(b)
	2021	2020
Residential	928	810	14.6	%	6.6	%
Small commercial & industrial	305	294	3.7	%	(0.8)	%
Large commercial & industrial	716	735	(2.6)	%	(3.5)	%
Public authorities & electric railroads	13	13	—	%	0.9	%
Total electric retail deliveries(a)	1,962	1,852	5.9	%	1.5	%

	As of March 31,
Number of Electric Customers	2021	2020
Residential	498,396	495,444
Small commercial & industrial	61,771	61,470
Large commercial & industrial	3,267	3,355
Public authorities & electric railroads	704	684
Total	564,138	560,953

_________

(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 months ended March 31, 2021 compared to the same period in 2020.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue.

Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.

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 acts as the billing agent and therefore 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 $29 million for the three months ended March 31, 2021 compared to the same period in 2020, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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ACE

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

	Three Months Ended March 31, 2021
	Increase (Decrease)
Labor, other benefits, contracting and materials	$	1
BSC and PHISCO costs	1
	2
Regulatory required programs(a)	(4)
Total decrease	$	(2)

_________

(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 March 31, 2021
	Increase (Decrease)
Depreciation and amortization(a)	$	4
Regulatory asset amortization	(1)
Regulatory required programs	1
Total increase	$	4

_________

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Gain on sale of assets for the three months ended March 31, 2021 compared to the same period in 2020 decreased due to the sale of land in the first quarter of 2020.

Effective income tax rates were 0.0% and 7.1% for the three months ended March 31, 2021 and 2020, respectively. See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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Liquidity and Capital Resources

All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, the sale of certain receivables, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $10.6 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 12 — 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 letters of credit or parent company guarantees for Generation’s share of the funding assurance. However, the amount of any guarantees or other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. 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. Considering the different approaches to decommissioning available to Generation, the most likely estimates currently anticipated could require financial assurance for radiological decommissioning at Byron of up to $55 million.

Upon issuance of any required financial guarantees, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, under the regulations, the NRC must approve an exemption in order for Generation to utilize the

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NDT funds to pay for non-radiological decommissioning costs (i.e. spent fuel management and site restoration 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 most likely decommissioning approach 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 $180 million, net of taxes, over a period of 10 years after permanent shutdown.

As of March 31, 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 would be required to allow the funds to be spent on site restoration costs, which are not expected to be incurred in the near term.

Project Financing (Exelon and Generation)

Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities. Refer to Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K 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 three months ended March 31, 2021 and 2020 by Registrant:

Decrease in cash flows from operating activities	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income	$	(640)	$	(608)	$	29	$	27	$	28	$	20	$	7	$	11	$	1
Adjustments to reconcile net income to cash:
Non-cash operating activities	(484)		(391)		15		(6)		(18)		(8)		(1)		4		(7)
Pension and non-pension postretirement benefit contributions	(6)		27		(28)		—		(1)		(9)		(1)		—		(1)
Income taxes	169		3		(16)		(11)		(16)		(12)		(4)		(4)		(1)
Changes in working capital and other noncurrent assets and liabilities	(1,728)		(1,609)		(50)		(30)		(136)		(14)		(14)		(11)		6
Option premiums received (paid), net	54		54		—		—		—		—		—		—		—
Collateral received (posted), net	294		292		2		—		—		—		—		—		—
Decrease in cash flows from operating activities	$	(2,341)	$	(2,232)	$	(48)	$	(20)	$	(143)	$	(23)	$	(13)	$	—	$	(2)

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 three months ended March 31, 2021 and 2020 were as follows:

•See Note 17 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statement of Cash Flows for additional information on non-cash operating activities.

•See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statement of Cash Flows for additional information on income taxes.

•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.

Cash Flows from Investing Activities (All Registrants)

The following table provides a summary of the change in cash flows from investing activities for the three months ended March 31, 2021 and 2020 by Registrant:

Increase (decrease) in cash flows from investing activities	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	(124)	$	176	$	(107)	$	(36)	$	(53)	$	(80)	$	(40)	$	(17)	$	(22)
Proceeds from NDT fund sales, net	20		20		—		—		—		—		—		—		—
Proceeds from sales of assets and businesses	680		680		—		—		—		—		—		—		—
Changes in intercompany money pool	—		254		—		(26)		—		—		114		—		—
Collection of DPP	1,574		1,574		—		—		—		—		—		—		—
Other investing activities	20		6		2		—		8		—		5		4		(6)
Increase (decrease) in cash flows from investing activities	$	2,170	$	2,710	$	(105)	$	(62)	$	(45)	$	(80)	$	79	$	(13)	$	(28)

Significant investing cash flow impacts for the Registrants for three months ended March 31, 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.

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•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.

Capital Expenditure Spending

As of March 31, 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 three months ended March 31, 2021 and 2020 by Registrant:

Increase (decrease) in cash flows from financing activities	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	488	$	222	$	(58)	$	—	$	90	$	(268)	$	47	$	(144)	$	(171)
Long-term debt, net	6		(508)		(300)		375		—		437		—		125		311
Changes in intercompany money pool	—		(285)		—		(40)		—		(4)		—		(37)		(77)
Dividends paid on common stock	(1)		—		(2)		—		(12)		—		—		12		9
Distributions to member	—		10		—		—		—		53		—		—		—
Contributions from parent/member	—		—		73		(231)		—		416		1		114		302
Other financing activities	(24)		(4)		4		(4)		—		(4)		—		(2)		(3)
Increase (decrease) in cash flows from financing activities	$	469	$	(565)	$	(283)	$	100	$	78	$	630	$	48	$	68	$	371

Significant financing cash flow impacts for the Registrants for the three months ended March 31, 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 12 — 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 12 — 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 three months ended March 31, 2021, other financing activities primarily consists of debt issuance costs. See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.

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Debt

See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

During the three months ended March 31, 2021, the following long-term debt was retired and/or redeemed:

Company(a)	Type	Interest Rate		Maturity	Amount
Generation	Continental Wind Nonrecourse Debt(b)	6.00	%	February 28, 2033	$	19
Generation	SolGen Nonrecourse Debt(b)	3.93	%	September 30, 2036	6
Generation	Antelope Valley DOE Nonrecourse Debt(b)	2.29 % - 3.56 %		January 5, 2037	5
Generation	RPG Nonrecourse Debt(b)	4.11	%	March 31, 2035	3
Generation	EGR IV Nonrecourse Debt(b)	3 month LIBOR + 2.75 %		December 15, 2027	2
ACE	Tax-Exempt First Mortgage Bonds	6.80	%	March 1, 2021	39
ACE	Transition Bonds	5.55	%	October 20, 2021	5

_________

(a)On April 15, 2021, Exelon Corporate redeemed $300 million of 2.45% senior notes. On April 1, 2021, ACE redeemed $200 million of 4.35% first mortgage bonds.

(b)See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on nonrecourse debt.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the three months ended March 31, 2021 and for the second 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

_________

(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 $10.6 billion in aggregate total commitments of which $6.9 billion was available to support additional commercial paper as of March 31, 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 first quarter of 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 March 31, 2021, it would have been required to provide incremental collateral of approximately $1.4 billion to meet collateral obligations for derivatives, non-derivatives, normal purchases and normal sales contracts, and applicable

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payables and receivables, net of the contractual right of offset under master netting agreements, which is well within the $3.5 billion of available credit capacity of its revolver.

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at March 31, 2021 and available credit facility capacity prior to any incremental collateral at March 31, 2021:

	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	20	$	—	$	863
PECO	14		32		600
BGE	3		48		444
Pepco	3		—		300
DPL	3		12		300
ACE	—		—		300

_________

(a)Represents incremental collateral related to natural gas procurement contracts.

Exelon Credit Facilities

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

See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ short-term borrowing activity. See Note 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 11 — 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 three months ended March 31, 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. The PHI intercompany money pool had no activity for the three months ended March 31, 2021. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of March 31, 2021, are presented in the following table:

	During the Three Months Ended March 31, 2021				As of March 31, 2021
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	735	$	—	$	267
Generation	—		(426)		—
PECO	135		(100)		48
BSC	—		(432)		(346)
PHI Corporate	—		(40)		(24)
PCI	60		—		55

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 March 31, 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	1,100
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 March 31, 2021 and has an expiration date of February 1, 2024 and February 1, 2023, respectively.

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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 14 — 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 March 31, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% 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 March 31, 2021 market conditions and hedged position would be an increase in pre-tax net income of approximately $31 million for 2021. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Fuel Procurement

Approximately 60% of Generation’s uranium concentrate requirements from 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 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding commodity price risk exposure.

Trading and Non-Trading Marketing Activities

The following table detailing Exelon’s, Generation’s, and ComEd’s trading and non-trading marketing activities are included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

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The following table provides detail on changes in Exelon’s, Generation’s, and ComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, 2020 to March 31, 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 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of March 31, 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	243		243		—
Reclassification to realized at settlement of contracts recorded in results of operations	(61)		(61)		—
Changes in fair value — recorded through regulatory assets(b)	6		—		6
Changes in allocated collateral	(270)		(270)		—
Net option premium paid	(16)		(16)		—
Option premium amortization	(17)		(17)		—
Upfront payments and amortizations(c)	(128)		(128)		—
Total mark-to-market energy contract net assets (liabilities) at March 31, 2021(a)	$	185	$	480	$	(295)

_________

(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 March 31, 2021, ComEd recorded a regulatory asset of $295 million related to its mark-to-market derivative liabilities with unaffiliated suppliers. For the three months ended March 31, 2021, ComEd recorded $2 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.

(c)Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.

Fair Values

The following tables present maturity and source of fair value for Exelon, Generation, and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 13 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

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Exelon

	Maturities Within												Total Fair Value
	2021		2022		2023		2024		2025		2026 and Beyond
Normal Operations, Commodity derivative contracts(a)(b):
Actively quoted prices (Level 1)	$	(27)	$	(6)	$	14	$	16	$	18	$	—	$	15
Prices provided by external sources (Level 2)	138		103		17		(1)		1		—		258
Prices based on model or other valuation methods (Level 3)(c)	(53)		95		42		(11)		(13)		(148)		(88)
Total	$	58	$	192	$	73	$	4	$	6	$	(148)	$	185

_________

(a)Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.

(b)Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $169 million at March 31, 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)	$	(27)	$	(6)	$	14	$	16	$	18	$	—	$	15
Prices provided by external sources (Level 2)	138		103		17		(1)		1		—		258
Prices based on model or other valuation methods (Level 3)	(29)		124		71		17		15		9		207
Total	$	82	$	221	$	102	$	32	$	34	$	9	$	480

_________

(a)Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.

(b)Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $169 million at March 31, 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)	$	(24)	$	(29)	$	(29)	$	(28)	$	(28)	$	(157)	$	(295)

_________

(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 11 — 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 March 31, 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 March 31, 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	$	431	$	31	$	400	—	$	—
Non-investment grade	43		4		39
No external ratings
Internally rated — investment grade	146		1		145
Internally rated — non-investment grade	70		25		45
Total	$	690	$	61	$	629	—	$	—

	Maturity of Credit Risk Exposure
Rating as of March 31, 2021	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	332	$	52	$	47	$	431
Non-investment grade	43		—		—		43
No external ratings
Internally rated — investment grade	109		25		12		146
Internally rated — non-investment grade	48		16		6		70
Total	$	532	$	93	$	65	$	690

Net Credit Exposure by Type of Counterparty	As of March 31, 2021
Investor-owned utilities, marketers, power producers	$	451
Energy cooperatives and municipalities	123
Other	55
Total	$	629

_________

(a)As of March 31, 2021, credit collateral held from counterparties where Generation had credit exposure included $32 million of cash and $29 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 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding credit exposure to suppliers.

Credit-Risk-Related Contingent Features (All Registrants)

Generation

As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase of electricity, natural gas, and other commodities. In accordance with the contracts and

165

applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.

Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s financial statements. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See Note 17 — Debt and Credit Agreements of Exelon’s 2020 Annual Report on Form 10-K for additional information.

Utility Registrants

As of March 31, 2021, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Exelon and Generation use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon and Generation may also utilize interest rate swaps to manage their interest rate exposure. A hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in an immaterial decrease in Exelon pre-tax income for the three months ended March 31, 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 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Equity Price Risk (Exelon and Generation)

Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of March 31, 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 $844 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 first 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 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

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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 March 31, 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 first 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 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.

ITEM 1A.    RISK FACTORS

Risks Related to All Registrants

At March 31, 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	One Hundred and Nineteenth Supplemental Indenture, dated as of February 15, 2021 from PECO to U.S. Bank National Association, as trustee (File No. 000-16844, Form 8-K dated March 8, 2021, Exhibit 4.1)
4.2	Supplemental Indenture, dated as of February 16, 2021, from ComEd to BNY Mellon Trust Company of Illinois, as trustee, and D.G. Donovan, as co-trustee (File No. 001-01839, Form 8-K dated March 9, 2021, Exhibit 4.1)
4.3	ACE Indenture Supplemental to Mortgage and Deed of Trust, dated as of February 15, 2021 (File No. 001-03559, Form 8-K dated March 10, 2021, Exhibit 4.1)
4.4	DPL Supplemental Indenture to the Mortgage and Deed of Trust, dated as of February 15, 2021 (File No. 001-01405, Form 8-K dated March 30, 2021, Exhibit 4.2)
4.5	Pepco Supplemental Indenture to the Mortgage and Deed of Trust, dated as of February 15, 2021 (File No. 001-01072, Form 8-K dated March 30, 2021, Exhibit 4.4)
4.6*	One Hundred and Twenty-Eighth Supplemental Indenture, dated January 1, 2021, between DPL and the Bank of New York, as trustee
10.1	Amendment No. 2 to Receivables Purchase Agreement, dated as of March 29, 2021, among Constellation NewEnergy, Inc., as servicer, and NewEnergy Receivables LLC, as seller, MUFG Bank, LTD., as agent, the Conduits party thereto, the Financial Institutions party thereto and the Purchaser Agents party thereto (File No. 001-16169, Form 8-K, dated March 31, 2021, Exhibit 10.1)
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 March 31, 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

169

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 March 31, 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

170

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)

May 5, 2021

171

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)

May 5, 2021

172

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)

May 5, 2021

173

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,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)

May 5, 2021

174

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)

May 5, 2021

175

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, 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)

May 5, 2021

176

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)

May 5, 2021

177

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)

May 5, 2021

178

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)

May 5, 2021

179