EXELON CORP - Quarter Report: 2023 June (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the Quarterly Period Ended June 30, 2023


☐ 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

001-01839	COMMONWEALTH EDISON COMPANY	36-0938600
	(an Illinois corporation) 10 South Dearborn Street Chicago, Illinois 60603-2300 (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 20068-0001 (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 20068-001 (202) 872-2000

001-01405	DELMARVA POWER & LIGHT COMPANY	51-0084283
	(a Delaware and Virginia corporation) 500 North Wakefield Drive Newark, Delaware 19702-5440 (202) 872-2000

001-03559	ATLANTIC CITY ELECTRIC COMPANY	21-0398280
	(a New Jersey corporation) 500 North Wakefield Drive Newark, Delaware 19702-5440 (202) 872-2000

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

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

EXELON CORPORATION:

Common stock, without par value

EXC

The Nasdaq Stock Market LLC

PECO ENERGY COMPANY:

Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company

EXC/28

New York Stock Exchange

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

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

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

Exelon Corporation

Large Accelerated Filer

Accelerated Filer

☐

Non-accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

Commonwealth Edison Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

PECO Energy Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

Baltimore Gas and Electric Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

Pepco Holdings LLC

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

Potomac Electric Power Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

Delmarva Power & Light Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

Atlantic City Electric Company

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

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

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

The number of shares outstanding of each registrant’s common stock as of June 30, 2023 was:


Exelon Corporation Common Stock, without par value			995,219,195
Commonwealth Edison Company Common Stock, $12.50 par value			127,021,395
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		7
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION		7
WHERE TO FIND MORE INFORMATION		7
PART I.	FINANCIAL INFORMATION	8
ITEM 1.	FINANCIAL STATEMENTS	8
	Exelon Corporation
	Consolidated Statements of Operations and Comprehensive Income	9
	Consolidated Statements of Cash Flows	10
	Consolidated Balance Sheets	11
	Consolidated Statements of Changes in Shareholders’ Equity	13
	Commonwealth Edison Company
	Consolidated Statements of Operations and Comprehensive Income	15
	Consolidated Statements of Cash Flows	16
	Consolidated Balance Sheets	17
	Consolidated Statements of Changes in Shareholders' Equity	19
	PECO Energy Company
	Consolidated Statements of Operations and Comprehensive Income	20
	Consolidated Statements of Cash Flows	21
	Consolidated Balance Sheets	22
	Consolidated Statements of Changes in Shareholder's Equity	24
	Baltimore Gas and Electric Company
	Statements of Operations and Comprehensive Income	25
	Statements of Cash Flows	26
	Balance Sheets	27
	Statements of Changes in Shareholder's Equity	29
	Pepco Holdings LLC
	Consolidated Statements of Operations and Comprehensive Income	30
	Consolidated Statements of Cash Flows	31
	Consolidated Balance Sheets	32
	Consolidated Statements of Changes in Member's Equity	34


						Page No.
			Potomac Electric Power Company
			Statements of Operations and Comprehensive Income			35
			Statements of Cash Flows			36
			Balance Sheets			37
			Statements of Changes in Shareholder's Equity			39
			Delmarva Power & Light Company
			Statements of Operations and Comprehensive Income			40
			Statements of Cash Flows			41
			Balance Sheets			42
			Statements of Changes in Shareholder’s Equity			44
			Atlantic City Electric Company
			Consolidated Statements of Operations and Comprehensive Income			45
			Consolidated Statements of Cash Flows			46
			Consolidated Balance Sheets			47
			Consolidated Statements of Changes in Shareholder’s Equity			49
			Combined Notes to Consolidated Financial Statements
			1. Significant Accounting Policies			50
			2. Discontinued Operations			51
			3. Regulatory Matters			54
			4. Revenue from Contracts with Customers			61
			5. Segment Information			62
			6. Accounts Receivable			71

			7. Income Taxes			74
			8. Retirement Benefits			77
			9. Derivative Financial Instruments			78
			10. Debt and Credit Agreements			82
			11. Fair Value of Financial Assets and Liabilities			85
			12. Commitments and Contingencies			91
			13. Shareholders' Equity			99
			14. Changes in Accumulated Other Comprehensive Income			99

			15. Supplemental Financial Information			100
			16. Related Party Transactions			105


		Page No.


ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	108
	Exelon Corporation	108
	Executive Overview	108
	Financial Results of Operations	108
	Significant 2023 Transactions and Developments	111


	Other Key Business Drivers and Management Strategies	113
	Critical Accounting Policies and Estimates	114
	Results of Operations By Registrant	116
	Commonwealth Edison Company	116
	PECO Energy Company	119
	Baltimore Gas and Electric Company	123
	Pepco Holdings LLC	126
	Potomac Electric Power Company	127
	Delmarva Power & Light Company	130
	Atlantic City Electric Company	134
	Liquidity and Capital Resources	137

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	145
ITEM 4.	CONTROLS AND PROCEDURES	146
PART II.	OTHER INFORMATION	146
ITEM 1.	LEGAL PROCEEDINGS	146
ITEM 1A.	RISK FACTORS	147

ITEM 5.	OTHER INFORMATION	147
ITEM 6.	EXHIBITS	147
SIGNATURES		150
	Exelon Corporation	150
	Commonwealth Edison Company	151
	PECO Energy Company	152
	Baltimore Gas and Electric Company	153
	Pepco Holdings LLC	154
	Potomac Electric Power Company	155
	Delmarva Power & Light Company	156
	Atlantic City Electric Company	157

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon						Exelon Corporation
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, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively
Utility Registrants						ComEd, PECO, BGE, Pepco, DPL, and ACE, collectively


BSC						Exelon Business Services Company, LLC
Exelon Corporate						Exelon in its corporate capacity as a holding company
PCI						Potomac Capital Investment Corporation and its subsidiaries
PECO Trust III						PECO Energy Capital Trust III
PECO Trust IV						PECO Energy Capital Trust IV

PHI Corporate						PHI in its corporate capacity as a holding company
PHISCO						PHI Service Company
Former Related Entities
Constellation						Constellation Energy Corporation
Generation						Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLC, a subsidiary of Exelon prior to separation on February 1, 2022)

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note - of the 2022 Form 10-K						Reference to specific Combined Note to Consolidated Financial Statements within Exelon's 2022 Annual Report on Form 10-K
ABO						Accumulated Benefit Obligation
AECs						Alternative Energy Credits that are issued for each megawatt hour of generation from a qualified alternative energy source
AFUDC						Allowance for Funds Used During Construction
AMI						Advanced Metering Infrastructure
AOCI						Accumulated Other Comprehensive Income (Loss)
ARO						Asset Retirement Obligation
BGS						Basic Generation Service
BSA						Bill Stabilization Adjustment
CEJA						Climate and Equitable Jobs Act; Illinois Public Act 102-0662 signed into law on September 15, 2021
CERCLA						Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended
CIP						Conservation Incentive Program
CMC						Carbon Mitigation Credit
CODMs						Chief Operating Decision Makers
DC PLUG						District of Columbia Power Line Undergrounding Initiative
DCPSC						Public Service Commission of the District of Columbia
DEPSC						Delaware Public Service Commission
DOEE						District of Columbia Department of Energy & Environment
DPA						Deferred Prosecution Agreement
DPP						Deferred Purchase Price
DSIC						Distribution System Improvement Charge
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
ERISA						Employee Retirement Income Security Act of 1974, as amended
ERP						Enterprise Resource Program
ETAC						Energy Transition Assistance Charge
FEJA						Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC						Federal Energy Regulatory Commission
GAAP						Generally Accepted Accounting Principles in the United States
GCR						Gas Cost Rate
GSA						Generation Supply Adjustment
GWhs						Gigawatt hours
ICC						Illinois Commerce Commission
IIJA						Infrastructure Investment and Jobs Act
IIP						Infrastructure Investment Program
Illinois Settlement Legislation						Legislation enacted in 2007 affecting electric utilities in Illinois
IPA						Illinois Power Agency
IRA						Inflation Reduction Act
IRC						Internal Revenue Code
IRS						Internal Revenue Service

MDPSC						Maryland Public Service Commission

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
MGP						Manufactured Gas Plant
mmcf						Million Cubic Feet
MMG						Middle Mile Grant
MRP						Multi-Year Rate Plan
MW						Megawatt
MWh						Megawatt hour
N/A						Not applicable
NAV						Net Asset Value
NDT						Nuclear Decommissioning Trust
NJBPU						New Jersey Board of Public Utilities
NPNS						Normal Purchase Normal Sale scope exception
NPS						National Park Service
NRD						Natural Resources Damages
OCI						Other Comprehensive Income
OPEB						Other Postretirement Employee Benefits
PAPUC						Pennsylvania Public Utility Commission
PGC						Purchased Gas Cost Clause
PJM						PJM Interconnection, LLC
POLR						Provider of Last Resort
PPA						Power Purchase Agreement
PP&E						Property, plant, and equipment
PRPs						Potentially Responsible Parties
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
ROE						Return on equity
ROU						Right-of-use
RPS						Renewable Energy Portfolio Standards
RTO						Regional Transmission Organization
SEC						United States Securities and Exchange Commission
SOFR						Secured Overnight Financing Rate
SOS						Standard Offer Service
STRIDE						Maryland Strategic Infrastructure Development and Enhancement Program
TCJA						Tax Cuts and Jobs Act
ZEC						Zero Emission Credit or Zero Emission Certificate

Table of Contents

FILING FORMAT

This combined Form 10-Q is being filed separately by Exelon Corporation, 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. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” "should," 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 2022 Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 12, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.

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

WHERE TO FIND MORE INFORMATION

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

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions, except per share data)	2023		2022		2023		2022
Operating revenues
Electric operating revenues	$	4,434	$	3,934	$	8,896	$	8,415
Natural gas operating revenues	258		307		1,080		1,124
Revenues from alternative revenue programs	126		(2)		404		27
Total operating revenues	4,818		4,239		10,380		9,566
Operating expenses
Purchased power	1,669		1,167		3,402		2,748
Purchased fuel	58		107		416		445
Purchased power and fuel from affiliates	—		—		—		159
Operating and maintenance	1,197		1,109		2,347		2,288
Depreciation and amortization	866		830		1,727		1,647
Taxes other than income taxes	324		330		679		684
Total operating expenses	4,114		3,543		8,571		7,971

Loss on sale of assets and businesses	—		(2)		—		(2)


Operating income	704		694		1,809		1,593
Other income and (deductions)
Interest expense, net	(421)		(352)		(828)		(684)
Interest expense to affiliates	(6)		(6)		(12)		(13)
Other, net	139		175		249		313
Total other income and (deductions)	(288)		(183)		(591)		(384)
Income from continuing operations before income taxes	416		511		1,218		1,209
Income taxes	73		46		206		263

Net income from continuing operations after income taxes	343		465		1,012		946
Net income from discontinued operations after income taxes (Note 2)	—		—		—		117
Net income	343		465		1,012		1,063
Net income attributable to noncontrolling interests	—		—		—		1
Net income attributable to common shareholders	$	343	$	465	$	1,012	$	1,062

Amounts attributable to common shareholders:
Net income from continuing operations	343		465		1,012		946
Net income from discontinued operations	—		—		—		116
Net income attributable to common shareholders	$	343	$	465	$	1,012	$	1,062

Comprehensive income, net of income taxes
Net income	$	343	$	465	$	1,012	$	1,063
Other comprehensive income, net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	—		2		—		2
Actuarial loss reclassified to periodic benefit cost	3		10		6		24
Pension and non-pension postretirement benefit plans valuation adjustment	(3)		—		(13)		—
Unrealized gain on cash flow hedges	9		—		15		—



Other comprehensive income	9		12		8		26
Comprehensive income	352		477		1,020		1,089
Comprehensive income attributable to noncontrolling interests	—		—		—		1
Comprehensive income attributable to common shareholders	$	352	$	477	$	1,020	$	1,088

Average shares of common stock outstanding:
Basic	995		981		995		981
Assumed exercise and/or distributions of stock-based awards	1		1		1		1
Diluted	996		982		996		982

Earnings per average common share from continuing operations
Basic	$	0.34	$	0.47	$	1.02	$	0.96
Diluted	$	0.34	$	0.47	$	1.02	$	0.96

Earnings per average common share from discontinued operations
Basic	$	—	$	—	$	—	$	0.12
Diluted	$	—	$	—	$	—	$	0.12

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2023		2022
Cash flows from operating activities
Net income	$	1,012	$	1,063
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	1,727		1,854


Gain on sales of assets and businesses	—		(8)

Deferred income taxes and amortization of investment tax credits	94		143
Net fair value changes related to derivatives	4		(59)
Net realized and unrealized losses on NDT funds	—		205
Net unrealized losses on equity investments	—		16
Other non-cash operating activities	(222)		276
Changes in assets and liabilities:
Accounts receivable	387		(795)
Inventories	44		12
Accounts payable and accrued expenses	(734)		544
Option premiums paid, net	—		(39)
Collateral (paid) received, net	(187)		1,689
Income taxes	97		23
Regulatory assets and liabilities, net	(516)		(376)
Pension and non-pension postretirement benefit contributions	(85)		(585)
Other assets and liabilities	140		(723)
Net cash flows provided by operating activities	1,761		3,240
Cash flows from investing activities
Capital expenditures	(3,685)		(3,507)
Proceeds from NDT fund sales	—		488
Investment in NDT funds	—		(516)
Collection of DPP	—		169


Proceeds from sales of assets and businesses	—		16


Other investing activities	10		4
Net cash flows used in investing activities	(3,675)		(3,346)
Cash flows from financing activities
Changes in short-term borrowings	(1,600)		(597)
Proceeds from short-term borrowings with maturities greater than 90 days	400		1,150
Repayments on short-term borrowings with maturities greater than 90 days	(150)		(350)
Issuance of long-term debt	5,200		5,151
Retirement of long-term debt	(1,209)		(1,707)





Dividends paid on common stock	(717)		(663)
Proceeds from employee stock plans	19		17
Transfer of cash, restricted cash, and cash equivalents to Constellation	—		(2,594)
Other financing activities	(84)		(84)
Net cash flows provided by financing activities	1,859		323
(Decrease) increase in cash, restricted cash, and cash equivalents	(55)		217
Cash, restricted cash, and cash equivalents at beginning of period	1,090		1,619
Cash, restricted cash, and cash equivalents at end of period	$	1,035	$	1,836

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(164)	$	(276)
Increase in DPP	—		348
Decrease in PP&E related to ARO update	—		(335)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
ASSETS
Current assets
Cash and cash equivalents	$	399	$	407
Restricted cash and cash equivalents	435		566

Accounts receivable
Customer accounts receivable	2,333		2,544
Customer allowance for credit losses	(323)		(327)
Customer accounts receivable, net	2,010		2,217
Other accounts receivable	1,107		1,426
Other allowance for credit losses	(87)		(82)
Other accounts receivable, net	1,020		1,344
Inventories, net
Fossil fuel	88		208
Materials and supplies	622		547
Regulatory assets	2,505		1,641
Other	463		406
Total current assets	7,542		7,336
Property, plant, and equipment (net of accumulated depreciation and amortization of $16,819 and $15,930 as of June 30, 2023 and December 31, 2022, respectively)	71,300		69,076
Deferred debits and other assets
Regulatory assets	7,972		8,037
Goodwill	6,630		6,630
Receivable related to Regulatory Agreement Units	3,120		2,897
Investments	238		232
Other	1,278		1,141
Total deferred debits and other assets	19,238		18,937
Total assets	$	98,080	$	95,349

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	1,236	$	2,586
Long-term debt due within one year	1,505		1,802
Accounts payable	2,506		3,382
Accrued expenses	1,220		1,226
Payables to affiliates	5		5
Regulatory liabilities	439		437
Mark-to-market derivative liabilities	31		8
Unamortized energy contract liabilities	8		10
Other	986		1,155
Total current liabilities	7,936		10,611
Long-term debt	39,492		35,272
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	11,547		11,250
Regulatory liabilities	9,406		9,112
Pension obligations	1,061		1,109
Non-pension postretirement benefit obligations	510		507
Asset retirement obligations	273		269
Mark-to-market derivative liabilities	109		83
Unamortized energy contract liabilities	30		35
Other	2,247		1,967
Total deferred credits and other liabilities	25,183		24,332
Total liabilities	73,001		70,605
Commitments and contingencies

Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 995 shares and 994 shares outstanding as of June 30, 2023 and December 31, 2022, respectively)	20,941		20,908
Treasury stock, at cost (2 shares as of June 30, 2023 and December 31, 2022)	(123)		(123)
Retained earnings	4,891		4,597
Accumulated other comprehensive loss, net	(630)		(638)
Total shareholders’ equity	25,079		24,744


Total liabilities and shareholders’ equity	$	98,080	$	95,349

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


	Six Months Ended June 30, 2023
(In millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Loss, net		Noncontrolling Interests		Total Shareholders' Equity
Balance at December 31, 2022	995,830	$	20,908	$	(123)	$	4,597	$	(638)	$	—	$	24,744
Net income	—	—		—		669		—		—		669
Long-term incentive plan activity	306	1		—		—		—		—		1
Employee stock purchase plan issuances	266	12		—		—		—		—		12




Common stock dividends ($0.36/common share)	—	—		—		(359)				—		(359)
Other comprehensive loss, net of income taxes	—	—		—		—		(1)		—		(1)

Balance at March 31, 2023	996,402	$	20,921	$	(123)	$	4,907	$	(639)	$	—	$	25,066
Net income	—	—		—		343		—		—		343
Long-term incentive plan activity	372	9		—		—		—		—		9
Employee stock purchase plan issuances	278	11		—		—		—		—		11




Common stock dividends ($0.36/common share)	—	—		—		(359)		—		—		(359)
Other comprehensive income, net of income taxes	—	—		—		—		9		—		9

Balance at June 30, 2023	997,052	$	20,941	$	(123)	$	4,891	$	(630)	$	—	$	25,079

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


	Six Months Ended June 30, 2022
(In millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Loss, net		Noncontrolling Interests		Total Shareholders' Equity
Balance at December 31, 2021	981,291	$	20,324	$	(123)	$	16,942	$	(2,750)	$	402	$	34,795
Net income	—	—		—		597		—		1		598
Long-term incentive plan activity	540	(13)		—		—		—		—		(13)
Employee stock purchase plan issuances	211	9		—		—		—		—		9

Changes in equity of noncontrolling interests	—	—		—		—		—		(7)		(7)

Distribution of Constellation (Note 2)	—	(21)		—		(13,179)		2,023		(396)		(11,573)
Common stock dividends ($0.34/common share)	—	—		—		(332)		—		—		(332)
Other comprehensive income, net of income taxes	—	—		—		—		14		—		14

Balance at March 31, 2022	982,042	$	20,299	$	(123)	$	4,028	$	(713)	$	—	$	23,491
Net income	—	—		—		465		—		—		465
Long-term incentive plan activity	21	10		—		—		—		—		10
Employee stock purchase plan issuances	242	10		—		—		—		—		10



Common stock dividends ($0.34/common share)	—	—		—		(332)		—		—		(332)
Other comprehensive income, net of income taxes	—	—		—		—		12		—		12
Balance at June 30, 2022	982,305	$	20,319	$	(123)	$	4,161	$	(701)	$	—	$	23,656

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2023		2022		2023		2022
Operating revenues
Electric operating revenues	$	1,781	$	1,387	$	3,293	$	3,075
Revenues from alternative revenue programs	118		35		270		75
Operating revenues from affiliates	2		3		5		8
Total operating revenues	1,901		1,425		3,568		3,158
Operating expenses
Purchased power	685		283		1,172		862
Purchased power from affiliate	—		—		—		59
Operating and maintenance	267		258		521		523
Operating and maintenance from affiliates	88		80		171		166
Depreciation and amortization	350		328		688		649
Taxes other than income taxes	88		90		182		185
Total operating expenses	1,478		1,039		2,734		2,444
Loss on sale of assets	—		(2)		—		(2)
Operating income	423		384		834		712
Other income and (deductions)
Interest expense, net	(117)		(101)		(230)		(197)
Interest expense to affiliates	(3)		(3)		(7)		(7)
Other, net	17		13		34		26
Total other income and (deductions)	(103)		(91)		(203)		(178)
Income before income taxes	320		293		631		534
Income taxes	71		66		142		119
Net income	$	249	$	227	$	489	$	415
Comprehensive income	$	249	$	227	$	489	$	415

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2023		2022
Cash flows from operating activities
Net income	$	489	$	415
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	688		649

Deferred income taxes and amortization of investment tax credits	106		122

Other non-cash operating activities	(260)		(18)
Changes in assets and liabilities:
Accounts receivable	(30)		(163)
Receivables from and payables to affiliates, net	(3)		(43)
Inventories	(43)		(2)
Accounts payable and accrued expenses	(311)		123
Collateral received, net	25		60
Income taxes	16		(19)
Regulatory assets and liabilities, net	(459)		(267)
Pension and non-pension postretirement benefit contributions	(24)		(178)
Other assets and liabilities	110		(91)
Net cash flows provided by operating activities	304		588
Cash flows from investing activities
Capital expenditures	(1,262)		(1,208)




Other investing activities	3		15
Net cash flows used in investing activities	(1,259)		(1,193)
Cash flows from financing activities
Changes in short-term borrowings	(130)		—
Proceeds from short-term borrowings with maturities greater than 90 days	400		—
Repayments on short-term borrowings with maturities greater than 90 days	(150)		—
Issuance of long-term debt	975		750

Dividends paid on common stock	(374)		(289)
Contributions from parent	372		335

Other financing activities	(13)		(12)
Net cash flows provided by financing activities	1,080		784
Increase in cash, restricted cash, and cash equivalents	125		179
Cash, restricted cash, and cash equivalents at beginning of period	511		384
Cash, restricted cash, and cash equivalents at end of period	$	636	$	563

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(7)	$	(44)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
ASSETS
Current assets
Cash and cash equivalents	$	74	$	67
Restricted cash and cash equivalents	361		327
Accounts receivable
Customer accounts receivable	786		558
Customer allowance for credit losses	(67)		(59)
Customer accounts receivable, net	719		499
Other accounts receivable	234		441
Other allowance for credit losses	(18)		(17)
Other accounts receivable, net	216		424

Receivables from affiliates	3		3

Inventories, net	238		196

Regulatory assets	1,609		775

Other	105		92
Total current assets	3,325		2,383
Property, plant, and equipment (net of accumulated depreciation and amortization of $6,985 and $6,673 as of June 30, 2023 and December 31, 2022, respectively)	28,283		27,513
Deferred debits and other assets
Regulatory assets	2,612		2,667

Goodwill	2,625		2,625

Receivable related to Regulatory Agreement Units	2,857		2,660
Investments	6		6
Prepaid pension asset	1,222		1,206

Other	742		601
Total deferred debits and other assets	10,064		9,765
Total assets	$	41,672	$	39,661

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	697	$	577

Accounts payable	728		1,010
Accrued expenses	396		415
Payables to affiliates	71		74
Customer deposits	112		108
Regulatory liabilities	196		226
Mark-to-market derivative liabilities	24		5

Other	210		191
Total current liabilities	2,434		2,606
Long-term debt	11,482		10,518
Long-term debt to financing trust	205		205
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	5,178		5,021
Regulatory liabilities	7,265		6,913
Asset retirement obligations	150		148

Non-pension postretirement benefits obligations	170		165

Mark-to-market derivative liabilities	109		79

Other	827		642
Total deferred credits and other liabilities	13,699		12,968
Total liabilities	27,820		26,297
Commitments and contingencies
Shareholders’ equity
Common stock	1,588		1,588


Other paid-in capital	10,118		9,746
Retained earnings	2,146		2,030

Total shareholders’ equity	13,852		13,364
Total liabilities and shareholders’ equity	$	41,672	$	39,661

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)


	Six Months Ended June 30, 2023
(In millions)	Common Stock		Other Paid-In Capital		Retained Earnings		Total Shareholders’ Equity
Balance at December 31, 2022	$	1,588	$	9,746	$	2,030	$	13,364
Net income	—		—		241		241
Common stock dividends	—		—		(187)		(187)
Contributions from parent	—		186		—		186
Balance at March 31, 2023	$	1,588	$	9,932	$	2,084	$	13,604
Net income	—		—		249		249
Common stock dividends	—		—		(187)		(187)
Contributions from parent	—		186		—		186
Balance at June 30, 2023	$	1,588	$	10,118	$	2,146	$	13,852





	Six Months Ended June 30, 2022
(In millions)	Common Stock		Other Paid-In Capital		Retained Earnings		Total Shareholders’ Equity
Balance at December 31, 2021	$	1,588	$	9,076	$	1,691	$	12,355
Net income	—		—		188		188
Common stock dividends	—		—		(144)		(144)
Contributions from parent	—		167		—		167
Balance at March 31, 2022	$	1,588	$	9,243	$	1,735	$	12,566
Net income	—		—		227		227
Common stock dividends	—		—		(145)		(145)
Contributions from parent	—		168		—		168
Balance at June 30, 2022	$	1,588	$	9,411	$	1,817	$	12,816

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2023		2022		2023		2022
Operating revenues
Electric operating revenues	$	723	$	707	$	1,521	$	1,441
Natural gas operating revenues	108		108		425		414
Revenues from alternative revenue programs	(5)		—		(10)		6
Operating revenues from affiliates	2		1		4		2
Total operating revenues	828		816		1,940		1,863
Operating expenses
Purchased power	267		244		597		472
Purchased fuel	35		39		189		184
Purchased power from affiliate	—		—		—		33
Operating and maintenance	186		168		405		364
Operating and maintenance from affiliates	53		47		105		99
Depreciation and amortization	99		93		197		185
Taxes other than income taxes	47		48		97		95
Total operating expenses	687		639		1,590		1,432

Operating income	141		177		350		431
Other income and (deductions)
Interest expense, net	(45)		(40)		(90)		(78)
Interest expense to affiliates	(3)		(3)		(7)		(6)
Other, net	6		8		15		16
Total other income and (deductions)	(42)		(35)		(82)		(68)
Income before income taxes	99		142		268		363
Income taxes	2		9		5		24

Net income	$	97	$	133	$	263	$	339
Comprehensive income	$	97	$	133	$	263	$	339

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2023		2022
Cash flows from operating activities
Net income	$	263	$	339
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	197		185


Deferred income taxes and amortization of investment tax credits	(26)		14
Other non-cash operating activities	12		4
Changes in assets and liabilities:
Accounts receivable	182		(29)
Receivables from and payables to affiliates, net	(3)		(40)
Inventories	52		(8)
Accounts payable and accrued expenses	(167)		5

Income taxes	56		49
Regulatory assets and liabilities, net	14		(24)
Pension and non-pension postretirement benefit contributions	(1)		(13)
Other assets and liabilities	(34)		(70)
Net cash flows provided by operating activities	545		412
Cash flows from investing activities
Capital expenditures	(707)		(658)
Changes in Exelon intercompany money pool	(225)		—

Other investing activities	—		5
Net cash flows used in investing activities	(932)		(653)
Cash flows from financing activities

Changes in short-term borrowings	(239)		210
Issuance of long-term debt	575		350
Retirement of long-term debt	(50)		(350)


Dividends paid on common stock	(202)		(200)
Contributions from parent	330		227


Other financing activities	(4)		(8)
Net cash flows provided by financing activities	410		229
Increase (decrease) in cash, restricted cash, and cash equivalents	23		(12)
Cash, restricted cash, and cash equivalents at beginning of period	68		44
Cash, restricted cash, and cash equivalents at end of period	$	91	$	32

Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	3	$	(11)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
ASSETS
Current assets
Cash and cash equivalents	$	82	$	59
Restricted cash and cash equivalents	9		9
Accounts receivable
Customer accounts receivable	448		635
Customer allowance for credit losses	(101)		(105)
Customer accounts receivable, net	347		530
Other accounts receivable	127		153
Other allowance for credit losses	(8)		(9)
Other accounts receivable, net	119		144

Receivables from affiliates	1		4
Receivable from Exelon intercompany money pool	225		—

Inventories, net
Fossil fuel	47		99
Materials and supplies	52		52
Prepaid utility taxes	68		—
Regulatory assets	102		80

Other	45		38
Total current assets	1,097		1,015
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,182 and $4,078 as of June 30, 2023 and December 31, 2022, respectively)	12,651		12,125
Deferred debits and other assets
Regulatory assets	717		652




Receivable related to Regulatory Agreement Units	263		237
Investments	32		30
Prepaid pension asset	421		413

Other	26		30
Total deferred debits and other assets	1,459		1,362
Total assets	$	15,207	$	14,502

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	239
Long-term debt due within one year	—		50
Accounts payable	530		668
Accrued expenses	165		142
Payables to affiliates	36		42

Customer deposits	72		63
Regulatory liabilities	116		75


Other	60		32
Total current liabilities	979		1,311
Long-term debt	5,132		4,562
Long-term debt to financing trusts	184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,263		2,213
Regulatory liabilities	295		270
Asset retirement obligations	28		28
Non-pension postretirement benefits obligations	287		286





Other	85		85
Total deferred credits and other liabilities	2,958		2,882
Total liabilities	9,253		8,939
Commitments and contingencies
Shareholder’s equity
Common stock	4,032		3,702


Retained earnings	1,922		1,861


Total shareholder’s equity	5,954		5,563
Total liabilities and shareholder's equity	$	15,207	$	14,502

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)


	Six Months Ended June 30, 2023
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2022	$	3,702	$	1,861	$	5,563
Net income	—		166		166
Common stock dividends	—		(101)		(101)
Contributions from parent	330		—		330
Balance at March 31, 2023	$	4,032	$	1,926	$	5,958
Net income	—		97		97
Common stock dividends	—		(101)		(101)

Balance at June 30, 2023	$	4,032	$	1,922	$	5,954





	Six Months Ended June 30, 2022
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2021	$	3,428	$	1,684	$	5,112
Net income	—		206		206
Common stock dividends	—		(100)		(100)
Contributions from parent	227		—		227
Balance at March 31, 2022	$	3,655	$	1,790	$	5,445
Net income	—		133		133
Common stock dividends	—		(100)		(100)

Balance at June 30, 2022	$	3,655	$	1,823	$	5,478

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2023		2022		2023		2022
Operating revenues
Electric operating revenues	$	670	$	642	$	1,449	$	1,377
Natural gas operating revenues	121		161		530		585
Revenues from alternative revenue programs	4		(20)		70		(32)
Operating revenues from affiliates	2		3		4		10
Total operating revenues	797		786		2,053		1,940
Operating expenses
Purchased power	261		241		604		526
Purchased fuel	11		48		160		199
Purchased power from affiliate	—		—		—		18
Operating and maintenance	144		154		311		321
Operating and maintenance from affiliates	54		51		108		102
Depreciation and amortization	158		152		325		322
Taxes other than income taxes	76		71		159		148
Total operating expenses	704		717		1,667		1,636

Operating income	93		69		386		304
Other income and (deductions)
Interest expense, net	(44)		(36)		(88)		(71)
Other, net	5		5		8		11
Total other income and (deductions)	(39)		(31)		(80)		(60)
Income before income taxes	54		38		306		244
Income taxes	12		1		65		10
Net income	$	42	$	37	$	241	$	234
Comprehensive income	$	42	$	37	$	241	$	234

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2023		2022
Cash flows from operating activities
Net income	$	241	$	234
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	325		322

Deferred income taxes and amortization of investment tax credits	38		13

Other non-cash operating activities	(36)		79
Changes in assets and liabilities:
Accounts receivable	185		(14)
Receivables from and payables to affiliates, net	(8)		(11)
Inventories	51		(27)
Accounts payable and accrued expenses	(114)		(12)
Collateral (paid) received, net	(22)		190
Income taxes	8		(27)
Regulatory assets and liabilities, net	(83)		(36)
Pension and non-pension postretirement benefit contributions	(11)		(59)
Other assets and liabilities	37		24
Net cash flows provided by operating activities	611		676
Cash flows from investing activities
Capital expenditures	(656)		(578)

Other investing activities	4		7
Net cash flows used in investing activities	(652)		(571)
Cash flows from financing activities
Changes in short-term borrowings	(408)		(130)
Issuance of long-term debt	700		500
Retirement of long-term debt	(300)		—


Dividends paid on common stock	(158)		(150)
Contributions from parent	237		186
Other financing activities	(7)		(7)
Net cash flows provided by financing activities	64		399
Increase in cash, restricted cash, and cash equivalents	23		504
Cash, restricted cash, and cash equivalents at beginning of period	67		55
Cash, restricted cash, and cash equivalents at end of period	$	90	$	559

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(60)	$	(21)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
ASSETS
Current assets
Cash and cash equivalents	$	89	$	43
Restricted cash and cash equivalents	1		24
Accounts receivable
Customer accounts receivable	440		617
Customer allowance for credit losses	(50)		(54)
Customer accounts receivable, net	390		563
Other accounts receivable	114		132
Other allowance for credit losses	(8)		(10)
Other accounts receivable, net	106		122




Inventories, net
Fossil fuel	34		91
Materials and supplies	71		65
Prepaid utility taxes	—		52
Regulatory assets	241		177

Other	18		13
Total current assets	950		1,150
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,737 and $4,583 as of June 30, 2023 and December 31, 2022, respectively)	11,673		11,338
Deferred debits and other assets
Regulatory assets	541		527
Investments	9		7


Prepaid pension asset	269		291

Other	46		37
Total deferred debits and other assets	865		862
Total assets	$	13,488	$	13,350

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	408
Long-term debt due within one year	—		300
Accounts payable	316		462
Accrued expenses	139		159
Payables to affiliates	32		39
Customer deposits	109		105
Regulatory liabilities	42		47


Other	32		55
Total current liabilities	670		1,575
Long-term debt	4,601		3,907
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,896		1,832
Regulatory liabilities	789		816
Asset retirement obligations	30		30
Non-pension postretirement benefits obligations	161		166



Other	85		88
Total deferred credits and other liabilities	2,961		2,932
Total liabilities	8,232		8,414
Commitments and contingencies
Shareholder's equity
Common stock	3,098		2,861

Retained earnings	2,158		2,075


Total shareholder's equity	5,256		4,936


Total liabilities and shareholder's equity	$	13,488	$	13,350

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)


	Six Months Ended June 30, 2023
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2022	$	2,861	$	2,075	$	4,936
Net income	—		200		200
Common stock dividends	—		(80)		(80)
Contributions from parent	237		—		237
Balance at March 31, 2023	$	3,098	$	2,195	$	5,293
Net income	—		42		42
Common stock dividends	—		(79)		(79)

Balance at June 30, 2023	$	3,098	$	2,158	$	5,256





	Six Months Ended June 30, 2022
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2021	$	2,575	$	1,995	$	4,570
Net income	—		198		198
Common stock dividends	—		(76)		(76)
Balance at March 31, 2022	$	2,575	$	2,117	$	4,692
Net income	—		37		37
Common stock dividends	—		(75)		(75)
Contributions from parent	186		—		186
Balance at June 30, 2022	$	2,761	$	2,079	$	4,840

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2023		2022		2023		2022
Operating revenues
Electric operating revenues	$	1,265	$	1,199	$	2,637	$	2,522
Natural gas operating revenues	29		37		126		120
Revenues from alternative revenue programs	9		(17)		74		(22)
Operating revenues from affiliates	2		2		4		6
Total operating revenues	1,305		1,221		2,841		2,626
Operating expenses
Purchased power	455		401		1,027		888
Purchased fuel	12		19		67		61
Purchased power from affiliate	—		—		—		50
Operating and maintenance	260		245		527		493
Operating and maintenance from affiliates	44		47		86		98
Depreciation and amortization	243		240		484		459
Taxes other than income taxes	112		114		232		233
Total operating expenses	1,126		1,066		2,423		2,282


Operating income	179		155		418		344
Other income and (deductions)
Interest expense, net	(81)		(73)		(157)		(143)

Other, net	25		19		51		37
Total other income and (deductions)	(56)		(54)		(106)		(106)
Income before income taxes	123		101		312		238
Income taxes	20		1		54		8

Net income	$	103	$	100	$	258	$	230








Comprehensive income	$	103	$	100	$	258	$	230

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2023		2022
Cash flows from operating activities
Net income	$	258	$	230
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	484		459


Deferred income taxes and amortization of investment tax credits	26		(7)

Other non-cash operating activities	20		76
Changes in assets and liabilities:
Accounts receivable	55		(92)
Receivables from and payables to affiliates, net	(8)		(53)
Inventories	(14)		(7)
Accounts payable and accrued expenses	(25)		10

Collateral (paid) received, net	(191)		403
Income taxes	6		(2)
Regulatory assets and liabilities, net	8		(71)
Pension and non-pension postretirement benefit contributions	(11)		(70)
Other assets and liabilities	(80)		(86)
Net cash flows provided by operating activities	528		790
Cash flows from investing activities
Capital expenditures	(1,022)		(776)




Other investing activities	8		3
Net cash flows used in investing activities	(1,014)		(773)
Cash flows from financing activities
Changes in short-term borrowings	(377)		(425)


Issuance of long-term debt	450		700
Retirement of long-term debt	—		(200)
Changes in Exelon intercompany money pool	8		17



Distributions to member	(212)		(395)
Contributions from member	405		704


Other financing activities	(25)		(12)
Net cash flows provided by financing activities	249		389
(Decrease) increase in cash, restricted cash, and cash equivalents	(237)		406
Cash, restricted cash, and cash equivalents at beginning of period	373		213
Cash, restricted cash, and cash equivalents at end of period	$	136	$	619

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(91)	$	(48)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
ASSETS
Current assets
Cash and cash equivalents	$	110	$	198
Restricted cash and cash equivalents	26		175
Accounts receivable
Customer accounts receivable	659		734
Customer allowance for credit losses	(105)		(109)
Customer accounts receivable, net	554		625
Other accounts receivable	304		300
Other allowance for credit losses	(53)		(46)
Other accounts receivable, net	251		254

Receivables from affiliates	2		2


Inventories, net
Fossil fuel	7		18
Materials and supplies	261		236


Regulatory assets	400		455

Other	84		96
Total current assets	1,695		2,059
Property, plant, and equipment (net of accumulated depreciation and amortization of $2,901 and $2,618 as of June 30, 2023 and December 31, 2022, respectively)	18,279		17,686
Deferred debits and other assets
Regulatory assets	1,589		1,610
Goodwill	4,005		4,005
Investments	141		138


Prepaid pension asset	311		353


Other	221		231
Total deferred debits and other assets	6,267		6,337
Total assets	$	26,241	$	26,082

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings	$	37	$	414
Long-term debt due within one year	996		591
Accounts payable	657		771
Accrued expenses	258		260
Payables to affiliates	58		66
Borrowings from Exelon intercompany money pool	52		44

Customer deposits	95		88
Regulatory liabilities	73		76
Unamortized energy contract liabilities	8		10

PPA termination obligation	74		87
Other	132		330
Total current liabilities	2,440		2,737
Long-term debt	7,554		7,529
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,967		2,895
Regulatory liabilities	958		1,011
Asset retirement obligations	60		59
Non-pension postretirement benefit obligations	45		50




Unamortized energy contract liabilities	30		35
Other	506		536
Total deferred credits and other liabilities	4,566		4,586
Total liabilities	14,560		14,852
Commitments and contingencies

Member's equity
Membership interest	11,987		11,582

Undistributed losses	(306)		(352)

Total member's equity	11,681		11,230
Total liabilities and member's equity	$	26,241	$	26,082

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY

(Unaudited)


	Six Months Ended June 30, 2023
(In millions)	Membership Interest		Undistributed (Losses)/Gains		Total Member's Equity
Balance at December 31, 2022	$	11,582	$	(352)	$	11,230
Net income	—		155		155
Distributions to member	—		(112)		(112)
Contributions from member	405		—		405
Balance at March 31, 2023	$	11,987	$	(309)	$	11,678
Net income	—		103		103
Distributions to member	—		(100)		(100)

Balance at June 30, 2023	$	11,987	$	(306)	$	11,681


	Six Months Ended June 30, 2022
(In millions)	Membership Interest		Undistributed (Losses)/Gains		Total Member's Equity
Balance at December 31, 2021	$	10,795	$	(210)	$	10,585
Net income	—		130		130
Distributions to member	—		(102)		(102)
Contributions from member	704		—		704
Balance at March 31, 2022	$	11,499	$	(182)	$	11,317
Net income	—		100		100
Distributions to member	—		(293)		(293)

Balance at June 30, 2022	$	11,499	$	(375)	$	11,124

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2023		2022		2023		2022
Operating revenues
Electric operating revenues	$	633	$	580	$	1,302	$	1,200
Revenues from alternative revenue programs	7		(1)		46		(7)
Operating revenues from affiliates	2		2		3		2
Total operating revenues	642		581		1,351		1,195
Operating expenses
Purchased power	204		162		462		336
Purchased power from affiliate	—		—		—		39
Operating and maintenance	82		72		175		145
Operating and maintenance from affiliates	58		56		115		115
Depreciation and amortization	109		105		216		213
Taxes other than income taxes	88		92		183		186
Total operating expenses	541		487		1,151		1,034



Operating income	101		94		200		161
Other income and (deductions)
Interest expense, net	(43)		(38)		(81)		(74)

Other, net	16		13		33		26
Total other income and (deductions)	(27)		(25)		(48)		(48)
Income before income taxes	74		69		152		113
Income taxes	10		(1)		22		(3)

Net income	$	64	$	70	$	130	$	116










Comprehensive income	$	64	$	70	$	130	$	116

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2023		2022
Cash flows from operating activities
Net income	$	130	$	116
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	216		213

Deferred income taxes and amortization of investment tax credits	12		(7)

Other non-cash operating activities	3		17
Changes in assets and liabilities:
Accounts receivable	12		(62)
Receivables from and payables to affiliates, net	(2)		(39)
Inventories	(10)		(6)
Accounts payable and accrued expenses	(21)		6
Collateral (paid) received, net	(26)		85
Income taxes	(1)		(24)
Regulatory assets and liabilities, net	(6)		(36)
Pension and non-pension postretirement benefit contributions	(8)		(7)
Other assets and liabilities	7		(15)
Net cash flows provided by operating activities	306		241
Cash flows from investing activities
Capital expenditures	(483)		(402)




Other investing activities	8		2
Net cash flows used in investing activities	(475)		(400)
Cash flows from financing activities
Changes in short-term borrowings	(299)		(132)
Issuance of long-term debt	250		400
Retirement of long-term debt	—		(200)
Changes in PHI intercompany money pool	52		73
Dividends paid on common stock	(115)		(300)
Contributions from parent	243		387


Other financing activities	(19)		(6)
Net cash flows provided by financing activities	112		222
(Decrease) increase in cash, restricted cash, and cash equivalents	(57)		63
Cash, restricted cash, and cash equivalents at beginning of period	99		68
Cash, restricted cash, and cash equivalents at end of period	$	42	$	131

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(43)	$	(24)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
ASSETS
Current assets
Cash and cash equivalents	$	16	$	45
Restricted cash and cash equivalents	26		54
Accounts receivable
Customer accounts receivable	337		351
Customer allowance for credit losses	(50)		(47)
Customer accounts receivable, net	287		304
Other accounts receivable	178		180
Other allowance for credit losses	(31)		(25)
Other accounts receivable, net	147		155




Inventories, net	145		135



Regulatory assets	212		235

Other	13		53
Total current assets	846		981
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,171 and $4,067 as of June 30, 2023 and December 31, 2022, respectively)	9,111		8,794
Deferred debits and other assets
Regulatory assets	443		437
Investments	122		119



Prepaid pension asset	259		273

Other	57		53
Total deferred debits and other assets	881		882
Total assets	$	10,838	$	10,657

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	299
Long-term debt due within one year	405		4
Accounts payable	310		382
Accrued expenses	126		125
Payables to affiliates	32		34


Borrowings from PHI intercompany money pool	52		—
Customer deposits	43		39
Regulatory liabilities	11		6
Merger related obligation	27		26

Other	58		93
Total current liabilities	1,064		1,008
Long-term debt	3,593		3,747

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,421		1,382
Regulatory liabilities	421		455
Asset retirement obligations	40		39






Other	260		244
Total deferred credits and other liabilities	2,142		2,120
Total liabilities	6,799		6,875
Commitments and contingencies
Shareholder's equity
Common stock	3,010		2,767


Retained earnings	1,029		1,015

Total shareholder's equity	4,039		3,782
Total liabilities and shareholder's equity	$	10,838	$	10,657

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)


	Six Months Ended June 30, 2023
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2022	$	2,767	$	1,015	$	3,782
Net income	—		65		65
Common stock dividends	—		(48)		(48)
Contributions from parent	243		—		243
Balance at March 31, 2023	$	3,010	$	1,032	$	4,042
Net income	—		64		64



Common stock dividends	—		(67)		(67)

Balance at June 30, 2023	$	3,010	$	1,029	$	4,039


	Six Months Ended June 30, 2022
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2021	$	2,302	$	1,173	$	3,475
Net income	—		46		46
Common stock dividends	—		(42)		(42)
Contributions from parent	387		—		387
Balance at March 31, 2022	$	2,689	$	1,177	$	3,866
Net income	—		70		70



Common stock dividends	—		(258)		(258)

Balance at June 30, 2022	$	2,689	$	989	$	3,678

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2023		2022		2023		2022
Operating revenues
Electric operating revenues	$	315	$	295	$	682	$	643
Natural gas operating revenues	29		37		126		120
Revenues from alternative revenue programs	3		(2)		12		(3)
Operating revenues from affiliates	2		2		3		3
Total operating revenues	349		332		823		763
Operating expenses
Purchased power	127		116		293		253
Purchased fuel	12		19		67		61
Purchased power from affiliate	—		—		—		10
Operating and maintenance	45		45		91		97
Operating and maintenance from affiliates	43		43		84		84
Depreciation and amortization	60		56		121		113
Taxes other than income taxes	18		17		37		35
Total operating expenses	305		296		693		653



Operating income	44		36		130		110
Other income and (deductions)
Interest expense, net	(18)		(17)		(36)		(33)
Other, net	4		4		8		6
Total other income and (deductions)	(14)		(13)		(28)		(27)
Income before income taxes	30		23		102		83
Income taxes	5		2		17		6

Net income	$	25	$	21	$	85	$	77
Comprehensive income	$	25	$	21	$	85	$	77

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2023		2022
Cash flows from operating activities
Net income	$	85	$	77
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	121		113

Deferred income taxes and amortization of investment tax credits	3		3

Other non-cash operating activities	2		13
Changes in assets and liabilities:
Accounts receivable	48		(8)
Receivables from and payables to affiliates, net	1		(3)
Inventories	5		1
Accounts payable and accrued expenses	(9)		12
Collateral (paid) received, net	(121)		180
Income taxes	11		6
Regulatory assets and liabilities, net	25		(11)
Pension and non-pension postretirement benefit contributions	—		(1)
Other assets and liabilities	10		1
Net cash flows provided by operating activities	181		383
Cash flows from investing activities
Capital expenditures	(258)		(194)


Changes in PHI intercompany money pool	(102)		(73)
Other investing activities	—		2
Net cash flows used in investing activities	(360)		(265)
Cash flows from financing activities
Changes in short-term borrowings	(115)		(149)
Issuance of long-term debt	125		125


Dividends paid on common stock	(60)		(56)
Contributions from parent	99		144
Other financing activities	(4)		(4)
Net cash flows provided by financing activities	45		60
(Decrease) increase in cash, restricted cash, and cash equivalents	(134)		178
Cash, restricted cash, and cash equivalents at beginning of period	152		71
Cash, restricted cash, and cash equivalents at end of period	$	18	$	249

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(3)	$	(5)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
ASSETS
Current assets
Cash and cash equivalents	$	18	$	31
Restricted cash and cash equivalents	—		121
Accounts receivable
Customer accounts receivable	149		204
Customer allowance for credit losses	(21)		(21)
Customer accounts receivable, net	128		183
Other accounts receivable	54		52
Other allowance for credit losses	(9)		(7)
Other accounts receivable, net	45		45

Receivable from PHI intercompany pool	102		—
Inventories, net
Fossil fuel	7		18
Materials and supplies	64		58


Regulatory assets	59		80

Other	23		37
Total current assets	446		573
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,854 and $1,772 as of June 30, 2023 and December 31, 2022, respectively)	4,974		4,820
Deferred debits and other assets
Regulatory assets	205		202


Prepaid pension asset	144		153
Other	54		54
Total deferred debits and other assets	403		409
Total assets	$	5,823	$	5,802

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	115
Long-term debt due within one year	584		584
Accounts payable	162		172
Accrued expenses	46		41
Payables to affiliates	23		22

Customer deposits	31		29
Regulatory liabilities	47		44
Other	17		136
Total current liabilities	910		1,143
Long-term debt	1,477		1,354
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	887		869
Regulatory liabilities	371		380
Asset retirement obligations	13		13

Non-pension postretirement benefits obligations	9		9
Other	82		84
Total deferred credits and other liabilities	1,362		1,355
Total liabilities	3,749		3,852
Commitments and contingencies
Shareholder's equity
Common stock	1,455		1,356

Retained earnings	619		594
Total shareholder's equity	2,074		1,950
Total liabilities and shareholder's equity	$	5,823	$	5,802

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)


	Six Months Ended June 30, 2023
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2022	$	1,356	$	594	$	1,950
Net income	—		60		60
Common stock dividends	—		(42)		(42)
Contributions from parent	99		—		99
Balance at March 31, 2023	$	1,455	$	612	$	2,067
Net income	—		25		25
Common stock dividends	—		(18)		(18)

Balance at June 30, 2023	$	1,455	$	619	$	2,074


	Six Months Ended June 30, 2022
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2021	$	1,209	$	568	$	1,777
Net income	—		56		56
Common stock dividends	—		(41)		(41)
Contributions from parent	144		—		144
Balance at March 31, 2022	$	1,353	$	583	$	1,936
Net income	—		21		21
Common stock dividends	—		(15)		(15)

Balance at June 30, 2022	$	1,353	$	589	$	1,942

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2023		2022		2023		2022
Operating revenues
Electric operating revenues	$	317	$	323	$	653	$	668
Revenues from alternative revenue programs	(1)		(15)		16		(12)
Operating revenues from affiliates	1		1		1		2
Total operating revenues	317		309		670		658
Operating expenses
Purchased power	124		123		273		299
Purchased power from affiliate	—		—		—		2
Operating and maintenance	48		50		91		97
Operating and maintenance from affiliates	37		36		74		73
Depreciation and amortization	68		72		135		118
Taxes other than income taxes	3		2		4		4
Total operating expenses	280		283		577		593



Operating income	37		26		93		65
Other income and (deductions)
Interest expense, net	(17)		(17)		(34)		(32)

Other, net	4		2		9		5
Total other income and (deductions)	(13)		(15)		(25)		(27)
Income before income taxes	24		11		68		38
Income taxes	6		—		17		1

Net income	$	18	$	11	$	51	$	37
Comprehensive income	$	18	$	11	$	51	$	37

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended June 30,
(In millions)	2023		2022
Cash flows from operating activities
Net income	$	51	$	37
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	135		118
Deferred income taxes and amortization of investment tax credits	12		—
Other non-cash operating activities	(3)		25
Changes in assets and liabilities:
Accounts receivable	(5)		(20)
Receivables from and payables to affiliates, net	(5)		(10)
Inventories	(9)		(2)
Accounts payable and accrued expenses	15		9
Collateral (paid) received, net	(45)		137
Income taxes	(4)		8
Regulatory assets and liabilities, net	(12)		(11)
Pension and non-pension postretirement benefit contributions	—		(7)
Other assets and liabilities	(89)		(63)
Net cash flows provided by operating activities	41		221
Cash flows from investing activities
Capital expenditures	(275)		(179)



Net cash flows used in investing activities	(275)		(179)
Cash flows from financing activities
Changes in short-term borrowings	37		(144)


Issuance of long-term debt	75		175

Changes in PHI intercompany money pool	50		—
Dividends paid on common stock	(36)		(38)
Contributions from parent	63		173
Other financing activities	(3)		(4)
Net cash flows provided by financing activities	186		162
(Decrease) increase in cash and cash equivalents	(48)		204
Cash and cash equivalents at beginning of period	72		29
Cash and cash equivalents at end of period	$	24	$	233

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(44)	$	(19)

See the Combined Notes to Consolidated Financial Statements

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ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
ASSETS
Current assets
Cash and cash equivalents	$	24	$	72

Accounts receivable
Customer accounts receivable	173		179
Customer allowance for credit losses	(34)		(41)
Customer accounts receivable, net	139		138
Other accounts receivable	71		70
Other allowance for credit losses	(13)		(14)
Other accounts receivable, net	58		56

Receivables from affiliates	2		1

Inventories, net	52		43


Prepaid utility taxes	43		—
Regulatory assets	116		130
Other	3		3
Total current assets	437		443
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,619 and $1,551 as of June 30, 2023 and December 31, 2022, respectively)	4,120		3,990
Deferred debits and other assets
Regulatory assets	488		494



Prepaid pension asset	11		18

Other	32		34
Total deferred debits and other assets	531		546
Total assets	$	5,088	$	4,979

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)


(In millions)	June 30, 2023		December 31, 2022
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	37	$	—
Long-term debt due within one year	3		3
Accounts payable	178		206
Accrued expenses	42		47
Payables to affiliates	22		26


Borrowings from PHI intercompany money pool	50		—
Customer deposits	22		21
Regulatory liabilities	15		26
PPA termination obligation	74		87
Other	12		58
Total current liabilities	455		474
Long-term debt	1,831		1,754
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	748		734
Regulatory liabilities	147		156


Non-pension postretirement benefit obligations	7		8



Other	69		100
Total deferred credits and other liabilities	971		998
Total liabilities	3,257		3,226
Commitments and contingencies
Shareholder's equity
Common stock	1,828		1,765
Retained earnings (deficit)	3		(12)

Total shareholder's equity	1,831		1,753
Total liabilities and shareholder's equity	$	5,088	$	4,979

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)


	Six Months Ended June 30, 2023
(In millions)	Common Stock		Retained (Deficit) Earnings		Total Shareholder's Equity
Balance at December 31, 2022	$	1,765	$	(12)	$	1,753
Net income	—		33		33
Common stock dividends	—		(21)		(21)
Contributions from parent	63		—		63
Balance at March 31, 2023	$	1,828	$	—	$	1,828
Net income	—		18		18
Common stock dividends	—		(15)		(15)

Balance at June 30, 2023	$	1,828	$	3	$	1,831


	Six Months Ended June 30, 2022
(In millions)	Common Stock		Retained Deficit		Total Shareholder's Equity
Balance at December 31, 2021	$	1,590	$	(15)	$	1,575
Net income	—		26		26
Common stock dividends	—		(19)		(19)
Contributions from parent	173		—		173
Balance at March 31, 2022	$	1,763	$	(8)	$	1,755
Net income	—		11		11
Common stock dividends	—		(19)		(19)

Balance at June 30, 2022	$	1,763	$	(16)	$	1,747

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 — Significant Accounting Policies

1. Significant Accounting Policies (All Registrants)

Description of Business

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

On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation. The separation was completed on February 1, 2022, creating two publicly traded companies, Exelon and Constellation. See Note 2 — Discontinued Operations for additional information.

Name of Registrant

Business

Service Territories

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

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, except for the historical transactions between the Utility Registrants and Generation for the purposes of presenting discontinued operations in all periods presented in the Consolidated Statements of Operations and Comprehensive Income.

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, finance, 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” in the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 — Significant Accounting Policies

The accompanying consolidated financial statements as of June 30, 2023 and for the three and six months ended June 30, 2023 and 2022 are unaudited but, in the opinion of each Registrant's management, the Registrants include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2022 Consolidated Balance Sheets were derived from audited financial statements. The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Additionally, 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, 2023. 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.

The separation of Constellation, including Generation and its subsidiaries, met the criteria for discontinued operations and as such, results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Comprehensive income, shareholders' equity, and cash flows related to Constellation have not been segregated and are included in the Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Changes in Shareholders’ Equity, and Consolidated Statements of Cash Flows, respectively, for the six months ended June 30, 2022. See Note 2 — Discontinued Operations for additional information.

2. Discontinued Operations (Exelon)

On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies ("the separation"). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purposes of separation and holds Generation (including Generation's subsidiaries). Pursuant to the separation, Exelon contributed its equity ownership interest in Generation to Constellation. Exelon no longer retains any equity ownership interest in Generation or Constellation. See Note 2 — Discontinued Operations of the 2022 Form 10-K for additional information.

Continuing Involvement

In order to govern the ongoing relationships between Exelon and Constellation after the separation, and to facilitate an orderly transition, Exelon and Constellation have entered into several agreements, including the following:

•Separation Agreement – governs the rights and obligations between Exelon and Constellation regarding certain actions to be taken in connection with the separation, among others, including the allocation of assets and liabilities between Exelon and Constellation.

•Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon provides to Constellation and Constellation provides to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits and other services that have historically been provided on a centralized basis by BSC. For the three and six months ended June 30, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $44 million and $94 million recorded in Other income, net and $3 million and $9 million recorded in Operating and maintenance expense, respectively. For the three months ended June 30, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $69 million recorded in Other income, net and $11 million recorded in Operating and maintenance expense, respectively. Additionally, for the period from February 1, 2022 to June 30, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $125 million recorded in Other income, net and $20 million recorded in Operating and maintenance expense, respectively.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Discontinued Operations

•Tax Matters Agreement (TMA) – governs the respective rights, responsibilities and obligations of Exelon and Constellation with respect to all tax matters, including tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. See Note 7 — Income Taxes for additional information.

In addition, the Utility Registrants will continue to incur expenses from transactions with Constellation after the separation. Prior to the separation, such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants. After the separation, such expenses are primarily recorded as Purchased power and an immaterial amount recorded as Operating and maintenance expense at the Utility Registrants.

•ComEd had an ICC-approved RFP contract with Constellation to provide a portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Constellation.

•PECO received electric supply from Constellation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with Constellation to sell solar AECs.

•BGE received a portion of its energy requirements from Constellation under its MDPSC-approved market-based SOS and gas commodity programs.

•Pepco received electric supply from Constellation under contracts executed through Pepco’s competitive procurement process approved by the MDPSC and DCPSC.

•DPL received a portion of its energy requirements from Constellation under its MDPSC and DEPSC approved market-based SOS commodity programs.

•ACE received electric supply from Constellation under contracts executed through ACE’s competitive procurement process approved by the NJBPU.

ComEd and PECO also have receivables with Constellation for estimated excess funds at the end of decommissioning the Regulatory Agreement Units, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 3 — Regulatory Matters and Note 23 — Related Party Transactions of the 2022 Form 10-K for additional information.

Discontinued Operations

The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations.

There were no results from discontinued operations for the three and six months ended June 30, 2023 and the three months ended June 30, 2022. The following table presents the results of Constellation that have been reclassified from continuing operations and included in discontinued operations within Exelon’s Consolidated Statements of Operations and Comprehensive Income for the six months ended June 30, 2022.

These results are primarily Generation, which is comprised of Exelon’s Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions reportable segments, and include the impact of transaction costs, certain BSC costs, including any transition costs, that were historically allocated and directly attributable to Generation, transactions between Generation and the Utility Registrants, and tax-related adjustments. Transaction costs include costs for external bankers, accountants, appraisers, lawyers, external counsels and other advisors, among others, who are involved in the negotiation, appraisal, due diligence and regulatory approval of the separation. Transition costs are primarily employee-related costs such as recruitment expenses, costs to establish certain stand-alone functions and information technology systems, professional services fees and other separation-related costs during the transition to separate Generation. For the purposes of reporting discontinued operations, these results also include transactions between Generation and the Utility Registrants that were historically eliminated within Exelon’s Consolidated Statements of Operations as these transactions will be ongoing after the separation. Certain BSC costs that were historically allocated to Generation are presented as part of continuing operations in Exelon’s Consolidated Statements of Operations as these costs do not qualify as expenses of the discontinued operations per the accounting rules.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Discontinued Operations


	Six Months Ended June 30,
	2022
Operating revenues
Competitive business revenues	$	1,855
Competitive business revenues from affiliates	161
Total operating revenues	2,016
Operating expenses
Competitive businesses purchased power and fuel	1,138

Operating and maintenance(a)	371

Depreciation and amortization	94
Taxes other than income taxes	44
Total operating expenses	1,647
Gain on sales of assets and businesses	10
Operating income	379
Other income and (deductions)
Interest expense, net	(20)

Other, net	(281)
Total other income and (deductions)	(301)
Income before income taxes	78
Income taxes	(40)
Equity in losses of unconsolidated affiliates	(1)
Net income	117
Net income attributable to noncontrolling interests	1
Net income from discontinued operations	$	116

__________

(a)Includes transaction and transition costs related to the separation of $52 million for the six months ended June 30, 2022.

There were no assets or liabilities of discontinued operations included in Exelon's Consolidated Balance Sheet as of June 30, 2023 and December 31, 2022. Constellation had net assets of $11,573 million that separated on February 1, 2022 that resulted in a reduction to Exelon's equity during the year ended December 31, 2022. Refer to the Distribution of Constellation line in Exelon's Consolidated Statement of Changes in Shareholders' Equity for further information.

There were no discontinued operations included within Exelon’s Consolidated Statements of Cash Flows for the six months ended June 30, 2023. The following table presents selected financial information regarding cash flows of the discontinued operations that are included within Exelon’s Consolidated Statements of Cash Flows for the six months ended June 30, 2022.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Discontinued Operations


	Six Months Ended June 30,
	2022
Non-cash items included in net income from discontinued operations:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	$	207

Loss on sales of assets and businesses	9
Deferred income taxes and amortization of investment tax credits	(143)
Net fair value changes related to derivatives	(59)
Net realized and unrealized losses on NDT fund investments	205
Net unrealized losses on equity investments	16
Other decommissioning-related activity	36
Cash flows from investing activities:
Capital expenditures	(227)
Collection of DPP	169
Supplemental cash flow information:
Decrease in capital expenditures not paid	(128)
Increase in DPP	348
Increase in PP&E related to ARO update	335

3. Regulatory Matters (All Registrants)

As discussed in Note 3 — Regulatory Matters of the 2022 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2023 and updates to the 2022 Form 10-K.

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2023.

Completed Distribution Base Rate Case Proceedings

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Regulatory Matters


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase		Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois(a)	April 15, 2022	Electric	$	199	$	199	7.85	%	November 17, 2022	January 1, 2023
PECO - Pennsylvania	March 31, 2022	Natural Gas	82		55		N/A(b)		October 27, 2022	January 1, 2023
BGE - Maryland(c)	May 15, 2020 (amended September 11, 2020)	Electric	203		140		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	108		74		9.65	%

Pepco - Maryland(d)	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021
DPL - Maryland(e)	May 19, 2022	Electric	38		29		9.60	%	December 14, 2022	January 1, 2023

__________

(a)ComEd's 2023 approved revenue requirement above reflects an increase of $144 million for the initial year revenue requirement for 2023 and an increase of $55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94%, inclusive of an allowed ROE of 7.85%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91%, inclusive of an allowed ROE of 7.78%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. This is ComEd's last performance-based electric distribution formula rate update filing under EIMA. See discussion of CEJA below for details on the transition away from the electric distribution formula rate.

(b)The PECO natural gas base rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.

(c)Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $59 million, $39 million, and $42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25% of the cumulative 2021 and 2022 electric revenue requirement increases and 50% of the cumulative gas revenue requirement increases. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases in 2023 and directed BGE to make another proposal at the end of 2022. In September 2022, BGE proposed that tax benefits not be used to offset the 2023 revenue requirement increases. On October 26, 2022, the MDPSC accepted BGE's recommendation to not use tax benefits to offset the 2023 revenue requirement increases.

(d)Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $21 million, $16 million, and $15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25% of the cumulative revenue requirement increase for the 12-month period ending March 31, 2023. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024.

(e)Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025. The MDPSC awarded DPL electric incremental revenue requirement increases of $17 million, $6 million, and $6 million for 2023, 2024, and 2025, respectively.

Table of Contents

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)

January 17, 2023

Electric

1,545

10.50% to 10.65%

Fourth quarter of 2023

ComEd - Illinois(b)

April 21, 2023

Electric

247

8.91%

Fourth quarter of 2023

BGE - Maryland(c)

February 17, 2023

Electric

313

10.40%

Fourth quarter of 2023

Natural Gas

289

10.40%

Pepco - District of Columbia(d)

April 13, 2023

Electric

191

10.50%

Second quarter of 2024

Pepco - Maryland(e)

May 16, 2023

Electric

214

10.50%

Second quarter of 2024

DPL - Delaware(f)

December 15, 2022 (amended May 30, 2023)

Electric

10.50%

Second quarter of 2024

ACE - New Jersey(g)

February 15, 2023 (amended June 2, 2023)

Electric

10.50%

First quarter of 2024

__________

(a)On June 27, 2023, ComEd submitted its MRP rebuttal testimony requesting an increase of the total revenue requirement increase to recover beneficial electrification costs through the MRP initially filed on January 17, 2023. The filing reflects a four-year cumulative MRP for January 1, 2024 to December 31, 2027 and total requested revenue requirement increases of $980 million effective January 1, 2024, $176 million effective January 1, 2025, $187 million effective January 1, 2026, and $202 million effective January 1, 2027, based on forecasted revenue requirements. If approved, the revenue requirement will provide for a weighted average debt and equity return on distribution rate base of 7.43% in 2024, 7.50% in 2025, 7.62% in 2026, and 7.70% in 2027, inclusive of an allowed ROE of 10.50% in 2024, 10.55% in 2025, 10.60% in 2026, and 10.65% in 2027. The requested revenue requirements are based on capital structures that reflect between 50.58% and 51.19% common equity. ComEd’s MRP also includes a proposed rate phase-in to defer approximately $343 million of the $980 million year-over-year increase for 2024 revenue from 2024 to 2026.

(b)On April 21, 2023, ComEd filed its proposed Delivery Reconciliation Amount of $247 million under Rider Delivery Service Pricing Reconciliation (Rider DSPR) which allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd’s approved MRP. The 2023 filing reconciles the delivery service rates in effect in 2022 with the actual delivery service costs incurred in 2022. Final order is expected by December 2023, and the reconciliation amount will be in customer rates beginning January 1, 2024.

(c)Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 submitted to the MDPSC. Inclusive of the proposed acceleration of remaining electric tax benefits in 2024 and 2025, and remaining gas tax benefits in 2024, BGE requested total electric revenue requirement increases of $85 million, $103 million, and $125 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $158 million, $77 million, and $54 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland’s climate and regulatory initiatives. The 2021 and 2022 reconciliation amounts are not included in the requested revenue requirement increase, as BGE is proposing that these amounts be recovered through the separate electric and gas riders in 2024. The 2021 reconciliation amounts are $11 million and $7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $44 million and $15 million for electric and gas, respectively.

(d)Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 submitted to the DCPSC. Pepco requested total electric revenue requirement increases of $117 million, $37 million, and $37 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support the District of Columbia’s climate and clean energy goals.

(e)Reflects a three-year cumulative multi-year plan for April 1, 2024 through March 31, 2027 submitted to the MDPSC. Pepco requested total electric revenue requirement increases of $74 million, $60 million and $60 million effective April 1, 2024, April 1, 2025, and April 1, 2026, respectively. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $20 million effective April 1, 2027 through December 31, 2027. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support Maryland's climate and clean energy goals. Based on a settlement agreement filed with the MDPSC on July 21, 2023, Pepco proposed to establish a revenue deferral mechanism that would allow for recovery of its full Commission-

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Regulatory Matters

authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the procedural schedule to address intervenor resource constraints. The settlement agreement remains subject to approval and Pepco cannot predict if the MDPSC will approve the settlement agreement as filed.

(f)The rates went into effect on July 15, 2023, subject to refund.

(g)Requested increases are before New Jersey sales and use tax. ACE intends to put rates into effect on November 17, 2023, subject to refund.

Transmission Formula Rates

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

For 2023, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:


Registrant(a)	Initial Revenue Requirement Increase		Annual Reconciliation Increase (Decrease)		Total Revenue Requirement Increase			Allowed Return on Rate Base(b)		Allowed ROE(c)
ComEd	$	20	$	63	$	83		8.09	%	11.50	%
PECO	24		23		47			7.41	%	10.35	%
BGE	19		(12)		4		(d)	7.34	%	10.50	%
Pepco	37		(5)		32			7.57	%	10.50	%
DPL	32		(3)		29			7.08	%	10.50	%
ACE	41		(12)		29			7.08	%	10.50	%

__________

(a)All rates are effective June 1, 2023 - May 31, 2024, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariffs.

(b)Represents the weighted average debt and equity return on transmission rate bases. For ComEd and PECO, the common equity component of the ratio used to calculate the weighted average debt and equity return on the transmission formula rate base is currently capped at 55% and 55.75%, respectively.

(c)The rate of return on common equity for each Utility Registrant includes a 50-basis-point incentive adder for being a member of a RTO.

(d)The increase in BGE's transmission revenue requirement includes a $3 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.

Other State Regulatory Matters

Illinois Regulatory Matters

CEJA (Exelon and ComEd). On September 15, 2021, the Governor of Illinois signed into law CEJA. CEJA includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate case or a new four-year MRP no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) an extension of and certain adjustments to ComEd’s energy efficiency MWh savings goals, (4) revisions to the Illinois RPS requirements, including expanded charges for the procurement of RECs from wind and solar generation, (5) a requirement to accelerate amortization of ComEd’s unprotected excess deferred income taxes (EDIT) that ComEd was previously directed by the ICC to amortize using the average rate assumption method which equates to approximately 39.5 years, and (6) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics.

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

Note 3 — Regulatory Matters

Regulatory or legal challenges regarding the validity or implementation of CEJA are possible and Exelon and ComEd cannot reasonably predict the outcome of any such challenges.

ComEd Electric Distribution Rates

ComEd filed, and received approval for, its last performance-based electric distribution formula rate update filing under EIMA in 2022; those rates are in effect throughout 2023.

On February 3, 2022, the ICC approved a tariff that establishes the process under which ComEd will reconcile its 2022 and 2023 rate year revenue requirements with actual costs. Those reconciliation amounts will be determined using the same process as were used for prior reconciliations under the performance-based electric distribution formula rate. Using that process, for the rate years 2022 and 2023 ComEd will ultimately collect revenues from customers reflecting each year’s actual recoverable costs, year-end rate base, and a weighted average debt and equity return on distribution rate base, with the ROE component based on the annual average of the monthly yields of the 30-year U.S. Treasury bonds plus 580 basis points. In April 2023, ComEd filed its first petition with the ICC to reconcile its 2022 actual costs with the approved revenue requirement that was in effect in 2022. The rate year 2023 reconciliation will be filed in 2024.

Beginning in 2024, ComEd will recover from retail customers, subject to certain exceptions, the costs it incurs to provide electric delivery services either through its electric distribution rate or other recovery mechanisms authorized by CEJA. On January 17, 2023, ComEd filed a petition with the ICC seeking approval of a MRP for 2024-2027. The MRP supports a multi-year grid plan (Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the MRP are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105% of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review during 2025. Discovery remains ongoing. On May 22, 2023, direct testimony was filed by ICC staff and more than a dozen intervenors and intervenor groups. The testimonies addressed a wide variety of topics, including rate of return on equity, capital structure, grid planning, various distribution grid and information technology investments, and affordability and customer service. ComEd filed rebuttal testimony in June, which provided, among other things, defense of ComEd’s planned 2024-2027 capital investment and proposed cost of equity. ComEd also made voluntary adjustments and, per the ICC’s final beneficial electrification order requiring ComEd to recover beneficial electrification costs through the MRP, increased its total revenue requirement request from $1.47 billion to $1.54 billion. On July 27, 2023, ICC staff and intervenors filed rebuttal testimony, which showed little to no movement on the key issues, including ROE and large capital projects. The ICC must issue its decision on both the MRP and Grid Plan by mid-December 2023, for rates to begin with the January 2024 billing cycle.

In January 2022, ComEd filed a request with the ICC proposing performance metrics that would be used in determining ROE incentives and penalties in the event ComEd filed a MRP in January 2023. On September 27, 2022, the ICC issued a final order approving seven performance metrics that provide symmetrical performance adjustments of 32 total basis points to ComEd’s rate of return on common equity based on the extent to which ComEd achieves the annual performance goals. On November 10, 2022, the ICC granted ComEd's application for rehearing, in part. On April 5, the ICC issued its final order on rehearing for the performance and tracking metrics proceeding, in which the ICC declined to adopt ComEd’s proposed modifications to the reliability and peak load reduction performance metrics. ComEd is determining how to implement the performance metrics, which take effect on January 1, 2024. ComEd will make its initial filing in 2025 to assess performance achieved under the metrics in 2024, and to determine any ROE adjustment, which would take effect in 2026.

Carbon Mitigation Credit

CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear-powered generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax

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

Note 3 — Regulatory Matters

credit or other subsidy if applicable. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. In the June 2022 billing period, ComEd began issuing credits to its retail customers under its new CMC rider. A regulatory asset is recorded for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. The balance as of June 30, 2023 is $1,079 million.

Under CEJA, the costs of procuring CMCs, including carrying costs, are recovered through a rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). The Rider CFRA provides for an annual reconciliation and true-up to actual costs incurred or credits received by ComEd to purchase CMCs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods. The difference between the net payments to (or receivables from) ComEd ratepayers and the credits received by ComEd to purchase CMCs is recorded to Purchased Power expense with an offset to the regulatory asset (or regulatory liability). On December 21, 2022, ComEd filed a supplemental statement to the Rider CFRA proposing that it recover costs or provide credits faster than the tariff allows, implement monthly reconciliations, and allow ComEd to adjust Rider CFRA rates based not only on anticipated differences but also past payments or credits. The ICC approved the proposal on January 19, 2023.

Beneficial Electrification Plan

On March 23, 2023, the ICC issued its final order approving the beneficial electrification plan for ComEd. The ICC rejected ComEd’s request to treat a large portion of beneficial electrification costs as a regulatory asset and ordered ComEd to seek cost recovery through the multi-year rate plan filing for 2024 and 2025, and the final formula rate reconciliation docket for 2023, rather than through a separate charge. The order also authorized an overall annual budget of $77 million per year for the three year plan period (2023 through 2025). On April 18, 2023, ComEd filed an application for rehearing in the beneficial electrification plan docket. The Chicago Transit Authority and City of Chicago, jointly, and the Office of the Illinois Attorney General (ILAG) also filed applications for rehearing. On April 27, 2023, ICC staff filed a motion for clarification, seeking clarification from the ICC on the precise budget described in the final order. On May 8, 2023, the ICC denied all applications for rehearing, and entered an amendatory order regarding the annual beneficial electrification plan budgets. ComEd has been directed to use good faith efforts to spend $77 million annually. ComEd subsequently filed its compliance filing in May 2023, detailing project related spending, clarifying the procedure that will be used to seek stakeholder feedback related to beneficial electrification pilot programs, and including the timeline for tariff changes required to implement the programs. There were also three pending appeals from the beneficial electrification case, one filed by ComEd and two by the ILAG. ComEd and the ILAG both filed appeals of the ICC’s interim order that addressed the permissible scope of utility beneficial electrification programs outside of transportation and the rate impact cap. The ILAG also filed an appeal seeking reversal of portions of the ICC’s final decision. The final order partly mooted ComEd’s appeal of the interim order and ComEd has decided not to pursue the other issues. As such, ComEd recently moved to voluntarily dismiss its appeal and the appellate court granted that request. The ILAG plans to consolidate their appeals.

Energy Efficiency Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on May 26, 2023. The filing establishes the revenue requirement used to set the rates that will take effect in January 2024 after the ICC's review and approval. The requested revenue requirement update is based on a reconciliation of the 2022 actual costs plus projected 2024 expenditures.


Initial Revenue Requirement Increase		Annual Reconciliation Increase		Total Revenue Requirement Increase		Requested Return on Rate Base(a)		Requested ROE
$	87	$	31	$	118	6.48	%	8.91	%

__________

(a)The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48% inclusive of an allowed ROE of 8.91%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 2022 reconciliation year, the requested revenue requirement provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.48% inclusive of an allowed ROE of 10.91%, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals.

New Jersey Regulatory Matters

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

Note 3 — Regulatory Matters

Termination of Energy Procurement Provisions of PPAs (Exelon, PHI, and ACE). On December 22, 2021, ACE filed with the NJBPU a petition to terminate the provisions in the PPAs to purchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was approved by the NJBPU on March 23, 2022. Upon closing of the transaction on March 31, 2022, ACE recognized a liability of $203 million for the contract termination fee, which is to be paid by the end of 2024, and recognized a corresponding regulatory asset of $203 million.

As of June 30, 2023, the $94 million liability for the contract termination fee consists of $74 million and $20 million included in Other current liabilities and Other deferred credits and other liabilities, respectively, in Exelon's Consolidated Balance Sheet. The current and noncurrent liabilities are included in PPA termination obligation and Other deferred credits and other liabilities, respectively, in PHI's and ACE's Consolidated Balance Sheets. For the six months ended June 30, 2023 and 2022, ACE has respectively paid $43 million and $23 million of the liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Cash Flows.

ACE Infrastructure Investment Program “Powering the Future” Filing (Exelon, PHI, and ACE). On October 31, 2022, ACE filed with the NJBPU a second IIP, called “Powering the Future”, proposing to seek recovery through a new component of ACE’s rider mechanism, totaling $379 million, over the four-year period of July 1, 2023, to June 30, 2027. The new IIP will allow ACE to invest in projects that are designed to enhance the reliability, resiliency, and safety of the service ACE provides to its customers. On June 15, 2023, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $93 million of reliability related capital investments from July 1, 2023, through June 30, 2027. ACE will have the option of seeking approval from the NJBPU to extend the end date of the IIP beyond June 30, 2027, if ACE determines an extension is necessary. On June 29, 2023, the NJBPU adopted the settlement agreement and issued an order approving the program.

Other Federal Regulatory Matters

FERC Audit (Exelon and ComEd). The Utility Registrants are subject to periodic audits by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates, and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit covered the period from January 1, 2017 to present. During the first quarter of 2023, ComEd was provided with information from FERC about several potential findings, including ComEd's methodology regarding the allocation of certain overhead costs to capital under FERC regulations. Based on the preliminary findings and discussions with FERC staff, ComEd determined that a loss was probable and recorded a regulatory liability to reflect its best estimate of that loss as of March 31, 2023.

On July 27, 2023, FERC issued a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations. ComEd disagrees with various findings and recommendations in the audit report, as indicated in ComEd's public reply to the report. The final outcome and resolution of any contested audit issues as well as a reasonable estimate of potential future losses cannot be accurately estimated at this stage; however, the final resolution of these matters could result in recognition of future losses, above the amounts currently accrued, that could be material to the Exelon and ComEd financial statements.

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2022, unless noted below. See Note 3 — Regulatory Matters of the 2022 Form 10-K for additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets increased $779 million primarily due to increases of $252 million in the Electric Distribution Formula Rate Annual Reconciliations regulatory asset, $236 million in the CMC regulatory asset, as discussed in CEJA above, and $145 million in the ZEC regulatory asset.

PECO. Regulatory assets increased $87 million primarily due to an increase of $76 million in the Deferred Income Taxes regulatory asset. Regulatory liabilities increased $66 million primarily due to increases of

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

Note 3 — Regulatory Matters

$55 million in the Electric Energy and Natural Gas Costs regulatory liability and $26 million in the Decommissioning the Regulatory Agreement Units regulatory liability.

BGE. Regulatory assets increased $78 million primarily due to an increase of $54 million in the Under-Recovered Revenue Decoupling regulatory asset.

Pepco. Regulatory liabilities decreased $29 million primarily due to a decrease of $27 million in the Deferred Income Taxes regulatory liability.

DPL. Regulatory assets decreased $18 million primarily due to a decrease of $21 million in the Electric Energy and Natural Gas Costs regulatory asset.

ACE. Regulatory assets decreased $20 million primarily due to a decrease of $45 million in the Electric Energy Costs regulatory asset as a result of the PPA termination.

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 the Registrants' 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. PECO had no related amounts at June 30, 2023 and December 31, 2022.


	Exelon		ComEd(a)		BGE(b)		PHI		Pepco(c)		DPL(c)		ACE(b)
June 30, 2023	$	63	$	19	$	23	$	21	$	18	$	2	$	1

December 31, 2022	57		8		28		21		18		2		1

__________

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

(b)BGE's and ACE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholder's investment on their respective AMI programs.

(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholder's investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs, and for Pepco District of Columbia revenue decoupling program. The earnings on energy efficiency are on Pepco District of Columbia and DPL Delaware programs only.

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. The 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 2022 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.

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 in Other current liabilities and Other noncurrent deferred credits and other liabilities in their Consolidated Balance Sheets.

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, PHI's, Pepco's, DPL's, and ACE's Consolidated Balance Sheets for the three and six months ended June 30, 2023 and 2022. At June 30, 2023 and December 31, 2022, ComEd's, PECO's, and BGE's contract liabilities were immaterial.

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

Note 4 — Revenue from Contracts with Customers



	Exelon(a)		PHI(a)		Pepco(a)		DPL		ACE(a)
Balance at December 31, 2022	$	101	$	101	$	81	$	10	$	10
Revenues recognized	(1)		(1)		(1)		—		—
Balance at March 31, 2023	100		100		80		10		10
Revenues recognized	(2)		(2)		(2)		—		—
Balance at June 30, 2023	$	98	$	98	$	78	$	10	$	10



	Exelon(a)		PHI(a)		Pepco(a)		DPL		ACE(a)
Balance at December 31, 2021	$	109	$	109	$	87	$	11	$	11
Revenues recognized	(2)		(2)		(2)		—		—
Balance at March 31, 2022	107		107		85		11		11
Revenues recognized	(2)		(2)		(1)		—		(1)
Balance at June 30, 2022	$	105	$	105	$	84	$	11	$	10

__________

(a)Revenues recognized in the three and six months ended June 30, 2023 and 2022, were included in the contract liabilities at December 31, 2022 and 2021, respectively.

Transaction Price Allocated to Remaining Performance Obligations

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of June 30, 2023. 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 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.


Year	Exelon		PHI		Pepco		DPL		ACE
2023	$	7	$	7	$	5	$	1	$	1
2024	6		6		5		—		1
2025	5		5		5		—		—
2026	5		5		5		—		—
2027 and thereafter	75		75		58		9		8
Total	$	98	$	98	$	78	$	10	$	10

Revenue Disaggregation

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 Registrants' revenue disaggregation.

5. Segment Information (All Registrants)

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

Exelon has six reportable segments, which include 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 the segments based on net income.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and six months ended June 30, 2023 and 2022 is as follows:

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

Note 5 — Segment Information

Three Months Ended June 30, 2023 and 2022



	ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2023
Electric revenues	$	1,901	$	719	$	672	$	1,274	$	—	$	(10)	$	4,556
Natural gas revenues	—		109		125		29		—		(1)		262
Shared service and other revenues	—		—		—		2		434		(436)		—
Total operating revenues	$	1,901	$	828	$	797	$	1,305	$	434	$	(447)	$	4,818
2022
Electric revenues	$	1,425	$	708	$	629	$	1,182	$	—	$	(6)	$	3,938
Natural gas revenues	—		108		157		37		—		(1)		301
Shared service and other revenues	—		—		—		2		384		(386)		—
Total operating revenues	$	1,425	$	816	$	786	$	1,221	$	384	$	(393)	$	4,239
Intersegment revenues(c):
2023	$	2	$	2	$	2	$	2	$	432	$	(440)	$	—
2022	3		1		3		2		384		(393)		—
Depreciation and amortization:
2023	$	350	$	99	$	158	$	243	$	16	$	—	$	866
2022	328		93		152		240		16		1		830
Operating expenses:
2023	$	1,478	$	687	$	704	$	1,126	$	561	$	(442)	$	4,114
2022	1,039		639		717		1,066		460		(378)		3,543
Interest expense, net:
2023	$	120	$	48	$	44	$	81	$	134	$	—	$	427
2022	104		43		36		73		101		1		358
Income (loss) from continuing operations before income taxes:
2023	$	320	$	99	$	54	$	123	$	(174)	$	(6)	$	416
2022	293		142		38		101		(62)		(1)		511
Income Taxes:
2023	$	71	$	2	$	12	$	20	$	(32)	$	—	$	73
2022	66		9		1		1		(31)		—		46
Net income (loss) from continuing operations:
2023	$	249	$	97	$	42	$	103	$	(142)	$	(6)	$	343
2022	227		133		37		100		(31)		(1)		465
Capital Expenditures:
2023	$	645	$	372	$	306	$	461	$	20	$	—	$	1,804
2022	591		314		275		367		38		—		1,585

__________

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

(c)See Note 16 — Related Party Transactions for additional information on intersegment revenues.

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

Note 5 — Segment Information

PHI:



	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2023
Electric revenues	$	642	$	320	$	317	$	—	$	(5)	$	1,274
Natural gas revenues	—		29		—		—		—		29
Shared service and other revenues	—		—		—		105		(103)		2
Total operating revenues	$	642	$	349	$	317	$	105	$	(108)	$	1,305
2022
Electric revenues	$	581	$	295	$	309	$	—	$	(3)	$	1,182
Natural gas revenues	—		37		—		—		—		37
Shared service and other revenues	—		—		—		98		(96)		2
Total operating revenues	$	581	$	332	$	309	$	98	$	(99)	$	1,221
Intersegment revenues(c):
2023	$	2	$	2	$	1	$	104	$	(107)	$	2
2022	2		2		1		98		(101)		2
Depreciation and amortization:
2023	$	109	$	60	$	68	$	6	$	—	$	243
2022	105		56		72		7		—		240
Operating expenses:
2023	$	541	$	305	$	280	$	108	$	(108)	$	1,126
2022	487		296		283		99		(99)		1,066
Interest expense, net:
2023	$	43	$	18	$	17	$	3	$	—	$	81
2022	38		17		17		1		—		73
Income (loss) before income taxes:
2023	$	74	$	30	$	24	$	(6)	$	1	$	123
2022	69		23		11		(2)		—		101
Income Taxes:
2023	$	10	$	5	$	6	$	(1)	$	—	$	20
2022	(1)		2		—		—		—		1
Net income (loss):
2023	$	64	$	25	$	18	$	(5)	$	1	$	103
2022	70		21		11		(2)		—		100
Capital Expenditures:
2023	$	219	$	124	$	114	$	4	$	—	$	461
2022	184		91		92		—		—		367

_________

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

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

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

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

The following tables disaggregate the Registrants' revenues 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 the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of electric sales and natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.



	Three Months Ended June 30, 2023
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	861	$	444	$	363	$	583	$	267	$	161	$	155
Small commercial & industrial	461		132		75		144		41		57		46
Large commercial & industrial	205		64		119		337		254		33		50
Public authorities & electric railroads	13		8		7		15		7		4		4
Other(a)	234		71		103		185		64		61		63
Total electric revenues(b)	$	1,774	$	719	$	667	$	1,264	$	633	$	316	$	318
Natural gas revenues
Residential	$	—	$	69	$	71	$	16	$	—	$	16	$	—
Small commercial & industrial	—		32		15		7		—		7		—
Large commercial & industrial	—		—		30		1		—		1		—
Transportation	—		5		—		4		—		4		—
Other(c)	—		2		5		1		—		1		—
Total natural gas revenues(d)	$	—	$	108	$	121	$	29	$	—	$	29	$	—
Total revenues from contracts with customers	$	1,774	$	827	$	788	$	1,293	$	633	$	345	$	318
Other revenues
Revenues from alternative revenue programs	$	118	$	(5)	$	4	$	9	$	7	$	3	$	(1)
Other electric revenues(e)	9		5		4		3		2		1		—
Other natural gas revenues(e)	—		1		1		—		—		—		—

Total other revenues	$	127	$	1	$	9	$	12	$	9	$	4	$	(1)
Total revenues for reportable segments	$	1,901	$	828	$	797	$	1,305	$	642	$	349	$	317

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information



	Three Months Ended June 30, 2022
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	819	$	431	$	334	$	548	$	234	$	155	$	159
Small commercial & industrial	312		126		70		140		35		51		54
Large commercial & industrial	11		72		129		332		250		30		52
Public authorities & electric railroads	5		7		7		15		8		3		4
Other(a)	234		68		99		164		54		57		55
Total electric revenues(b)	$	1,381	$	704	$	639	$	1,199	$	581	$	296	$	324
Natural gas revenues
Residential	$	—	$	71	$	96	$	17	$	—	$	17	$	—
Small commercial & industrial	—		29		18		8		—		8		—
Large commercial & industrial	—		—		35		3		—		3		—
Transportation	—		6		—		3		—		3		—
Other(c)	—		2		12		6		—		6		—
Total natural gas revenues(d)	$	—	$	108	$	161	$	37	$	—	$	37	$	—
Total revenues from contracts with customers	$	1,381	$	812	$	800	$	1,236	$	581	$	333	$	324
Other revenues
Revenues from alternative revenue programs	$	35	$	—	$	(20)	$	(17)	$	(1)	$	(2)	$	(15)
Other electric revenues(e)	9		4		4		2		1		1		—
Other natural gas revenues(e)	—		—		2		—		—		—		—

Total other revenues	$	44	$	4	$	(14)	$	(15)	$	—	$	(1)	$	(15)
Total revenues for reportable segments	$	1,425	$	816	$	786	$	1,221	$	581	$	332	$	309

__________

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

(b)Includes operating revenues from affiliates in 2023 and 2022 respectively of:

•$2 million, $3 million at ComEd

•$1 million, $1 million at PECO

•$1 million, $2 million at BGE

•$2 million, $2 million at PHI

•$2 million, $2 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 2023 and 2022 respectively of:

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

•$1 million, $1 million at BGE

(e)Includes late payment charge revenues.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

Six Months Ended June 30, 2023 and 2022


	ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2023
Electric revenues	$	3,568	$	1,514	$	1,485	$	2,711	$	—	$	(14)	$	9,264
Natural gas revenues	—		426		568		126		—		(4)		1,116
Shared service and other revenues	—		—		—		4		871		(875)		—
Total operating revenues	$	3,568	$	1,940	$	2,053	$	2,841	$	871	$	(893)	$	10,380
2022
Electric revenues	$	3,158	$	1,449	$	1,366	$	2,501	$	—	$	(14)	$	8,460
Natural gas revenues	—		414		574		120		—		(2)		1,106
Shared service and other revenues	—		—		—		5		961		(966)		—
Total operating revenues	$	3,158	$	1,863	$	1,940	$	2,626	$	961	$	(982)	$	9,566

Intersegment revenues(c):
2023	$	5	$	4	$	4	$	4	$	867	$	(884)	$	—
2022	8		2		10		6		961		(981)		6
Depreciation and amortization:
2023	$	688	$	197	$	325	$	484	$	31	$	2	$	1,727
2022	649		185		322		459		32		—		1,647
Operating expenses:
2023	$	2,734	$	1,590	$	1,667	$	2,423	$	1,046	$	(889)	$	8,571
2022	2,444		1,432		1,636		2,282		1,086		(909)		7,971
Interest expense, net:
2023	$	237	$	97	$	88	$	157	$	263	$	(2)	$	840
2022	204		84		71		143		195		—		697
Income (loss) from continuing operations before income taxes:
2023	$	631	$	268	$	306	$	312	$	(294)	$	(5)	$	1,218
2022	534		363		244		238		(125)		(45)		1,209
Income taxes:
2023	$	142	$	5	$	65	$	54	$	(60)	$	—	$	206
2022	119		24		10		8		114		(12)		263
Net income (loss) from continuing operations:
2023	$	489	$	263	$	241	$	258	$	(235)	$	(4)	$	1,012
2022	415		339		234		230		(239)		(33)		946
Capital expenditures:
2023	$	1,262	$	707	$	656	$	1,022	$	38	$	—	$	3,685
2022	1,208		658		578		776		60		—		3,280
Total assets:
June 30, 2023	$	41,672	$	15,207	$	13,488	$	26,241	$	5,922	$	(4,450)	$	98,080
December 31, 2022	39,661		14,502		13,350		26,082		6,014		(4,260)		95,349

__________

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

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

(c)See Note 16 — Related Party Transactions for additional information on intersegment revenues.

PHI:


	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2023
Electric revenues	$	1,351	$	697	$	670	$	—	$	(7)	$	2,711
Natural gas revenues	—		126		—		—		—		126
Shared service and other revenues	—		—		—		207		(203)		4
Total operating revenues	$	1,351	$	823	$	670	$	207	$	(210)	$	2,841
2022
Electric revenues	$	1,195	$	643	$	658	$	—	$	5	$	2,501
Natural gas revenues	—		120		—		—		—		120
Shared service and other revenues	—		—		—		205		(200)		5
Total operating revenues	$	1,195	$	763	$	658	$	205	$	(195)	$	2,626
Intersegment revenues(c):
2023	$	3	$	3	$	1	$	206	$	(209)	$	4
2022	2		3		2		195		(196)		6
Depreciation and amortization:
2023	$	216	$	121	$	135	$	12	$	—	$	484
2022	213		113		118		15		—		459
Operating expenses:
2023	$	1,151	$	693	$	577	$	212	$	(210)	$	2,423
2022	1,034		653		593		197		(195)		2,282
Interest expense, net:
2023	$	81	$	36	$	34	$	6	$	—	$	157
2022	74		33		32		5		(1)		143
Income (loss) before income taxes:
2023	$	152	$	102	$	68	$	(10)	$	—	$	312
2022	113		83		38		4		—		238
Income taxes:
2023	$	22	$	17	$	17	$	(2)	$	—	$	54
2022	(3)		6		1		4		—		8
Net income (loss):
2023	$	130	$	85	$	51	$	(8)	$	—	$	258
2022	116		77		37		—		—		230
Capital expenditures:
2023	$	483	$	258	$	275	$	6	$	—	$	1,022
2022	402		194		179		1		—		776
Total assets:
June 30, 2023	$	10,838	$	5,823	$	5,088	$	4,735	$	(243)	$	26,241
December 31, 2022	10,657		5,802		4,979		4,677		(33)		26,082

__________

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

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

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

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



	Six Months Ended June 30, 2023
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	1,698	$	963	$	796	$	1,221	$	549	$	371	$	301
Small commercial & industrial	823		267		167		304		80		119		105
Large commercial & industrial	290		129		268		714		535		66		113
Public authorities & electric railroads	22		16		14		33		16		8		9
Other(a)	450		139		198		362		120		119		126
Total electric revenues(b)	$	3,283	$	1,514	$	1,443	$	2,634	$	1,300	$	683	$	654
Natural gas revenues
Residential	$	—	$	292	$	349	$	76	$	—	$	76	$	—
Small commercial & industrial	—		107		56		33		—		33		—
Large commercial & industrial	—		1		100		2		—		2		—
Transportation	—		13		—		8		—		8		—
Other(c)	—		11		24		7		—		7		—
Total natural gas revenues(d)	$	—	$	424	$	529	$	126	$	—	$	126	$	—
Total revenues from contracts with customers	$	3,283	$	1,938	$	1,972	$	2,760	$	1,300	$	809	$	654
Other revenues
Revenues from alternative revenue programs	$	270	$	(10)	$	70	$	74	$	46	$	12	$	16
Other electric revenues(e)	15		10		8		7		5		2		—
Other natural gas revenues(e)	—		2		3		—		—		—		—

Total other revenues	$	285	$	2	$	81	$	81	$	51	$	14	$	16
Total revenues for reportable segments	$	3,568	$	1,940	$	2,053	$	2,841	$	1,351	$	823	$	670

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information



	Six Months Ended June 30, 2022
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	1,675	$	918	$	752	$	1,200	$	509	$	362	$	329
Small commercial & industrial	736		237		151		281		73		107		101
Large commercial & industrial	165		136		260		655		503		56		96
Public authorities & electric railroads	20		15		14		31		16		7		8
Other(a)	472		130		196		359		100		113		136
Total electric revenues(b)	$	3,068	$	1,436	$	1,373	$	2,526	$	1,201	$	645	$	670
Natural gas revenues
Residential	$	—	$	289	$	378	$	68	$	—	$	68	$	—
Small commercial & industrial	—		105		63		29		—		29		—
Large commercial & industrial	—		—		100		6		—		6		—
Transportation	—		14		—		7		—		7		—
Other(c)	—		5		47		10		—		10		—
Total natural gas revenues(d)	$	—	$	413	$	588	$	120	$	—	$	120	$	—
Total revenues from contracts with customers	$	3,068	$	1,849	$	1,961	$	2,646	$	1,201	$	765	$	670
Other revenues
Revenues from alternative revenue programs	$	75	$	6	$	(32)	$	(22)	$	(7)	$	(3)	$	(12)
Other electric revenues(e)	15		7		8		2		1		1		—
Other natural gas revenues(e)	—		1		3		—		—		—		—

Total other revenues	$	90	$	14	$	(21)	$	(20)	$	(6)	$	(2)	$	(12)
Total revenues for reportable segments	$	3,158	$	1,863	$	1,940	$	2,626	$	1,195	$	763	$	658

__________

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

(b)Includes operating revenues from affiliates in 2023 and 2022 respectively of:

•$5 million, $8 million at ComEd

•$3 million, $2 million at PECO

•$2 million, $3 million at BGE

•$4 million, $6 million at PHI

•$3 million, $2 million at Pepco

•$3 million, $3 million at DPL

•$1 million, $2 million at ACE

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

(d)Includes operating revenues from affiliates in 2023 and 2022 respectively of:

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

•$2 million, $7 million at BGE

(e)Includes late payment charge revenues.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

6. Accounts Receivable (All Registrants)

Allowance for Credit Losses on Accounts Receivable

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


	Three Months Ended June 30, 2023
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at March 31, 2023	$	389	$	74	$	130	$	73	$	112	$	49	$	26	$	37
Plus: Current period (benefit) provision for expected credit losses	(35)		(1)		(20)		(16)		2		4		(3)		1
Less: Write-offs, net of recoveries(a)	31		6		9		7		9		3		2		4
Balance at June 30, 2023	$	323	$	67	$	101	$	50	$	105	$	50	$	21	$	34

	Three Months Ended June 30, 2022
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at March 31, 2022	$	389	$	92	$	125	$	59	$	113	$	40	$	24	$	49
Plus: Current period (benefit) provision for expected credit losses	(9)		(5)		(10)		2		4		5		—		(1)
Less: Write-offs, net of recoveries	26		6		8		4		8		3		2		3
Balance at June 30, 2022	$	354	$	81	$	107	$	57	$	109	$	42	$	22	$	45

	Six Months Ended June 30, 2023
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2022	$	327	$	59	$	105	$	54	$	109	$	47	$	21	$	41
Plus: Current period provision for expected credit losses	71		21		18		14		18		13		4		1
Less: Write-offs, net(b)(c) of recoveries(a)	75		13		22		18		22		10		4		8
Balance at June 30, 2023	$	323	$	67	$	101	$	50	$	105	$	50	$	21	$	34

	Six Months Ended June 30, 2022
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2021	$	320	$	73	$	105	$	38	$	104	$	37	$	18	$	49
Plus: Current period provision for expected credit losses	101		21		21		28		31		16		7		8
Less: Write-offs, net of recoveries	67		13		19		9		26		11		3		12
Balance at June 30, 2022	$	354	$	81	$	107	$	57	$	109	$	42	$	22	$	45

__________

(a)Recoveries were not material to the Registrants.

(b)For PECO, the change in write-offs is primarily a result of increased disconnection activities.

(c)For ACE, the change in write-offs is primarily related to the termination of the moratoriums in New Jersey, which beginning in March 2020, prevented customer disconnections for non-payment. With disconnection activities restarting in January 2022, write-offs of aging accounts receivable increased during the year.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

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


	Three Months Ended June 30, 2023
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at March 31, 2023	$	91	$	18	$	11	$	12	$	50	$	28	$	8	$	14
Plus: Current period provision (benefit) for expected credit losses	1		1		(2)		(2)		4		3		1		—
Less: Write-offs, net of recoveries(a)	5		1		1		2		1		—		—		1
Balance at June 30, 2023	$	87	$	18	$	8	$	8	$	53	$	31	$	9	$	13

	Three Months Ended June 30, 2022
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at March 31, 2022	$	81	$	20	$	9	$	11	$	41	$	18	$	9	$	14
Plus: Current period provision (benefit) for expected credit losses	2		(2)		2		1		1		2		(1)		—
Less: Write-offs, net of recoveries	2		—		1		1		—		—		—		—
Balance at June 30, 2022	$	81	$	18	$	10	$	11	$	42	$	20	$	8	$	14

	Six Months Ended June 30, 2023
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2022	$	82	$	17	$	9	$	10	$	46	$	25	$	7	$	14
Plus: Current period provision for expected credit losses	15		3		1		2		9		6		2		1
Less: Write-offs, net of recoveries(a)	10		2		2		4		2		—		—		2
Balance at June 30, 2023	$	87	$	18	$	8	$	8	$	53	$	31	$	9	$	13

	Six Months Ended June 30, 2022
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2021	$	72	$	17	$	7	$	9	$	39	$	16	$	8	$	15
Plus: Current period provision for expected credit losses	15		2		4		4		5		4		—		1
Less: Write-offs, net of recoveries	6		1		1		2		2		—		—		2
Balance at June 30, 2022	$	81	$	18	$	10	$	11	$	42	$	20	$	8	$	14

__________

(a)Recoveries were not material to the Registrants.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

Unbilled Customer Revenue

The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets at June 30, 2023 and December 31, 2022.


	Unbilled customer revenues(a)
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2023	$	789	$	329	$	144	$	116	$	200	$	96	$	37	$	67
December 31, 2022	912		223		219		247		223		103		74		46

__________

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

Other Purchases of Customer and Other Accounts Receivables

The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, Delaware, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. The following table presents the total receivables purchased.


	Total receivables purchased
	Exelon			ComEd		PECO		BGE			PHI		Pepco		DPL		ACE
Six months ended June 30, 2023	$	1,979		$	445	$	546	$	420		$	568	$	371	$	107	$	90
Six months ended June 30, 2022	1,911		(a)	456		518		391		(a)	546		342		104		100

__________

(a)Includes $4 million of receivables purchased from Generation prior to the separation on February 1, 2022 for the six months ended June 30, 2022.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Income Taxes

7. Income Taxes (All Registrants)

Rate Reconciliation

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


	Three Months Ended June 30, 2023(a)
	Exelon		ComEd		PECO(b)		BGE		PHI		Pepco		DPL		ACE
U.S. Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	6.5		7.8		(1.2)		6.8		6.2		5.6		6.3		7.1
Plant basis differences	(4.8)		(0.6)		(15.8)		0.1		(1.6)		(2.6)		(1.1)		—
Excess deferred tax amortization	(7.4)		(5.6)		(2.4)		(5.3)		(8.0)		(9.9)		(9.9)		(2.0)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.1)		(0.1)		—		(0.1)		(0.1)		—		(0.1)		(0.1)
Tax credits	(0.5)		(0.3)		—		(0.4)		(0.9)		(1.1)		(0.4)		(0.3)
Other	2.8		—		0.4		0.1		(0.3)		0.5		0.9		(0.7)
Effective income tax rate	17.5	%	22.2	%	2.0	%	22.2	%	16.3	%	13.5	%	16.7	%	25.0	%


	Three Months Ended June 30, 2022(a)
	Exelon		ComEd		PECO(c)		BGE(c)		PHI		Pepco(c)		DPL		ACE(c)
U.S. Federal statutory rate	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(d)	(5.4)		7.9		(0.6)		2.1		1.5		(3.4)		7.2		6.7
Plant basis differences	(3.3)		(0.5)		(11.0)		(1.3)		(1.7)		(2.4)		(0.7)		(1.0)
Excess deferred tax amortization	(10.5)		(5.5)		(3.1)		(19.0)		(19.2)		(15.7)		(20.0)		(24.5)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.1)		(0.1)		—		(0.1)		(0.1)		—		(0.2)		(0.2)
Tax credits	(0.4)		(0.3)		—		(1.5)		(0.4)		(0.4)		(0.4)		(0.4)
Other(e)	7.7		—		—		1.4		(0.1)		(0.5)		1.8		(1.6)
Effective income tax rate	9.0	%	22.5	%	6.3	%	2.6	%	1.0	%	(1.4)	%	8.7	%	—	%

__________

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

(b)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.

(c)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions. For BGE, the lower effective tax rate is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For Pepco, the income tax benefit is primarily due to the Maryland and Washington, D.C. multi-year plans which resulted in the acceleration of certain income tax benefits. For ACE, the lower effective tax rate is primarily due to the acceleration of certain income tax benefits due to distribution rate case settlements.

(d)For Exelon, the lower state income taxes, net of federal income tax benefit, is primarily related to a one-time impact associated with a state tax benefit of $43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $5 million as a result of the separation.

(e)For Exelon, primarily related to indemnification adjustments pursuant to the Tax Matters Agreement of $48 million.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Income Taxes


	Six Months Ended June 30, 2023(a)
	Exelon	ComEd	PECO(b)	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	6.2	7.8	(1.3)	6.4	6.1	5.5	6.3	6.9
Plant basis differences	(4.3)	(0.4)	(15.4)	(0.6)	(1.7)	(2.6)	(1.0)	(0.6)
Excess deferred tax amortization	(6.7)	(5.6)	(2.4)	(5.4)	(7.4)	(9.1)	(9.2)	(2.0)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.1)	(0.1)	—	(0.1)	(0.1)	—	(0.1)	(0.1)
Tax credits	(0.5)	(0.3)	—	(0.4)	(0.6)	(0.8)	(0.4)	(0.3)
Other	1.3	0.1	—	0.3	—	0.5	0.1	0.1
Effective income tax rate	16.9%	22.5%	1.9%	21.2%	17.3%	14.5%	16.7%	25.0%


	Six Months Ended June 30, 2022(a)
	Exelon	ComEd	PECO(c)	BGE(c)	PHI	Pepco(c)	DPL	ACE(c)
U.S. Federal statutory rate	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(d)	9.9	7.9	(0.3)	2.3	2.8	(3.8)	6.5	6.7
Plant basis differences	(3.5)	(0.5)	(11.2)	(1.0)	(1.7)	(2.5)	(0.7)	(1.2)
Excess deferred tax amortization	(11.0)	(5.8)	(3.2)	(17.8)	(18.3)	(16.3)	(19.5)	(22.9)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.1)	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Tax credits(e)	0.8	(0.3)	—	(0.6)	(0.4)	(0.4)	(0.3)	(0.3)
Other(f)	4.7	0.1	0.3	0.3	0.1	(0.7)	0.4	(0.5)
Effective income tax rate	21.8%	22.3%	6.6%	4.1%	3.4%	(2.7)%	7.2%	2.6%

__________

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

(b)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.

(d)For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term marginal state income tax rate change of approximately $67 million and the recognition of a valuation allowance of approximately $40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with a state tax benefit of $43 million and indemnification adjustments pursuant to the Tax Matters Agreement of $4 million as a result of the separation.

(e)For Exelon, reflects the income tax expense related to the write-off of federal tax credits subject to recapture of approximately $15 million as a result of the separation.

(f)For Exelon, primarily reflects the nondeductible transaction costs of approximately $19 million arising as part of the separation and indemnification adjustments pursuant to the Tax Matters Agreement of $48 million.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Income Taxes

Unrecognized Tax Benefits

Exelon, PHI and ACE have the following unrecognized tax benefits at June 30, 2023 and December 31, 2022. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.


	Exelon(a)		PHI		ACE
June 30, 2023	$	148	$	59	$	17
December 31, 2022	148		59		17

__________

(a)At June 30, 2023 and December 31, 2022, Exelon recorded a receivable of $50 million in Other deferred debits and other assets in the Consolidated Balance Sheet for Constellation’s share of unrecognized tax benefits for periods prior to the separation.

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

As of June 30, 2023, ACE has $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.

Other Tax Matters

Tax Matters Agreement (Exelon)

In connection with the separation, Exelon entered into a TMA with Constellation. The TMA governs the respective rights, responsibilities, and obligations between Exelon and Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of Exelon’s consolidated group for U.S. federal, state, and local tax purposes.

Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have been responsible for such taxes under the existing Exelon tax sharing agreement. As of June 30, 2023, Exelon recorded a payable of $17 million in Other current liabilities that is due to Constellation.

Tax Refunds. The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the separation to the extent that Constellation would have received such tax refunds under the existing Exelon tax sharing agreement.

Tax Attributes. At the date of separation certain tax attributes, primarily pre-closing tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA provides that Exelon will reimburse Constellation when those allocated tax credit carryforwards are utilized. As of June 30, 2023, Exelon recorded a payable of $8 million and $524 million in Other current liabilities and Other deferred credits and other liabilities, respectively, in the Consolidated Balance Sheet for tax attribute carryforwards that are expected to be utilized and reimbursed to Constellation.

Corporate Alternative Minimum Tax (All Registrants)

On August 16, 2022, the IRA was signed into law and implements a new corporate alternative minimum tax (CAMT) that imposes a 15.0% tax on modified GAAP net income. Corporations are entitled to a tax credit (minimum tax credit) to the extent the CAMT liability exceeds the regular tax liability. This amount can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Income Taxes

Beginning in 2023, based on the existing statue, Exelon and each of the Utility Registrants will be subject to and will report the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets. The deferred tax asset related to the minimum tax credit carryforward will be realized to the extent Exelon’s consolidated deferred tax liabilities exceed the minimum tax credit carryforward. Exelon’s deferred tax liabilities are expected to exceed the minimum tax credit carryforward for the foreseeable future and thus no valuation allowance is required. Exelon is continuing to assess the financial statement impacts of the IRA and will update estimates based on future guidance issued by the U.S. Treasury.

8. Retirement Benefits (All Registrants)

Defined Benefit Pension and OPEB

The majority of the 2023 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 5.53%. The majority of the 2023 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.50% for funded plans and a discount rate of 5.51%.

During the first quarter of 2023, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2023. This valuation resulted in an increase to the pension obligation of $27 million and an increase to the OPEB obligation of $2 million. Additionally, AOCI increased by $10 million (after-tax) and regulatory assets and liabilities increased by $18 million and $1 million, respectively.

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and six months ended June 30, 2023 and 2022.


	Pension Benefits				OPEB
	Three Months Ended June 30,				Three Months Ended June 30,
	2023		2022		2023		2022
Components of net periodic benefit cost
Service cost	$	38	$	58	$	6	$	10
Interest cost	144		110		26		19
Expected return on assets	(188)		(205)		(21)		(25)
Amortization of:
Prior service cost (credit)	—		1		(3)		(5)
Actuarial loss (gain)	43		73		(1)		4


Net periodic benefit cost	$	37	$	37	$	7	$	3

	Pension Benefits				OPEB
	Six Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Components of net periodic benefit cost
Service cost	$	77	$	119	$	12	$	20
Interest cost	289		220		51		38
Expected return on assets	(377)		(414)		(42)		(50)
Amortization of:
Prior service cost (credit)	1		2		(5)		(10)
Actuarial loss (gain)	84		149		(1)		8


Net periodic benefit cost	$	74	$	76	$	15	$	6

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 the Utility Registrants, which

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 8 — Retirement Benefits

apply multi-employer accounting, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.


	Three Months Ended June 30,				Six Months Ended June 30,
Pension and OPEB Costs (Benefit)	2023		2022		2023		2022
Exelon	$	44	$	40	$	89	$	82
ComEd	7		14		13		30
PECO	(4)		(2)		(7)		(4)
BGE	14		11		28		22
PHI	25		13		49		26
Pepco	9		2		17		4
DPL	5		1		9		2
ACE	3		3		7		6

Defined Contribution Savings Plan

The Registrants participate in a 401(k) defined contribution savings plan that is sponsored by Exelon. The plan is qualified under applicable sections of the IRC and allows 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 employer contributions and employer matching contributions to the savings plan for the three and six months ended June 30, 2023 and 2022.


	Three Months Ended June 30,				Six Months Ended June 30,
Savings Plan Employer Contributions	2023		2022		2023		2022
Exelon	$	26	$	23	$	47	$	43
ComEd	10		10		19		18
PECO	4		3		7		6
BGE	3		3		5		5
PHI	5		4		8		7
Pepco	1		1		2		2
DPL	1		1		2		2
ACE	1		1		1		1

9. Derivative Financial Instruments (All Registrants)

The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations. The Registrants do not execute derivatives for speculative or proprietary trading purposes.

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. At ComEd, derivative economic hedges related to commodities are recorded at fair value and offset by a corresponding regulatory asset or liability. At Exelon, derivative economic hedges related to interest rates are recorded at fair value and offsets are recorded to Electric operating revenues or Interest expense based on the activity the transaction is economically hedging. 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. At Exelon, derivative hedges that qualify and are designated as cash flow hedges are recorded at fair value and offsets are recorded to AOCI.

ComEd’s use of cash collateral is generally unrestricted unless ComEd is 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 meets certain qualifications.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Derivative Financial Instruments

Commodity Price Risk

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


Registrant	Commodity	Accounting Treatment	Hedging Instrument
ComEd	Electricity	NPNS	Fixed price contracts based on all requirements in the IPA procurement plans.
	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)	20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO	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.
	Gas	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 2022 Form 10-K for additional information.

(b)The fair value of the DPL economic hedge is not material at June 30, 2023 and December 31, 2022.

The fair value of derivative economic hedges is presented in Other current assets and current and noncurrent Mark-to-market derivative liabilities in Exelon's and ComEd's Consolidated Balance Sheets.

Interest Rate and Other Risk (Exelon)

Exelon Corporate uses a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon Corporate may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. In addition, Exelon Corporate may also utilize interest rate swaps to manage interest rate exposure and manage potential fluctuations in Electric operating revenues at the corporate level in consolidation, which are directly correlated to yields on U.S. Treasury bonds under ComEd's distribution formula rate. These interest rate swaps are accounted for as economic hedges. A hypothetical 50

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Derivative Financial Instruments

basis point change in the interest rates associated with Exelon's interest rate swaps as of June 30, 2023 would result in an immaterial impact to Exelon's Consolidated Net Income.

Below is a summary of the interest rate hedge balances at June 30, 2023 and December 31, 2022.


	June 30, 2023
	Derivatives Designated as Hedging Instruments		Economic Hedges		Total

Other deferred debits (noncurrent assets)	$	12	$	5	$	17
Total derivative assets	12		5		17
Mark-to-market derivative liabilities (current liabilities)	—		(7)		(7)

Total mark-to-market derivative liabilities	—		(7)		(7)
Total mark-to-market derivative net assets (liabilities)	$	12	$	(2)	$	10


	December 31, 2022
	Derivatives Designated as Hedging Instruments		Economic Hedges		Total

Other deferred debits (noncurrent assets)	$	6	$	5	$	11
Total derivative assets	6		5		11
Mark-to-market derivative liabilities (current liabilities)	—		(3)		(3)
Mark-to-market derivative liabilities (noncurrent liabilities)	(4)		—		(4)
Total mark-to-market derivative liabilities	(4)		(3)		(7)
Total mark-to-market derivative net assets	$	2	$	2	$	4

Cash Flow Hedges (Interest Rate Risk)

For derivative instruments that qualify and are designated as cash flow hedges, the changes in fair value each period are initially recorded in AOCI and reclassified into earnings when the underlying transaction affects earnings. In January 2023, Exelon Corporate entered into $115 million notional of 5-year maturity floating-to-fixed swaps and $115 million notional of 10-year maturity floating-to-fixed swaps, for a total of $230 million designated as cash flow hedges. In February 2023, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $1.5 billion upon issuance of $2.5 billion of debt. See Note 10 – Debt and Credit Agreements for additional information on the debt issuance. Prior to the termination, the AOCI derivative gain was $7 million (net of tax). The settlements resulted in a cash receipt of $10 million, which is being amortized into Interest expense in Exelon's Consolidated Statement of Operations and Comprehensive Income over the 5-year and 10-year terms of the swaps. See Note 14 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.

Since the termination in February 2023, Exelon has entered into additional floating-to-fixed swaps. The following table provides the notional amounts outstanding held by Exelon at June 30, 2023 and December 31, 2022.


	June 30, 2023		December 31, 2022
5-year maturity floating-to-fixed swaps	$	260	$	635
10-year maturity floating-to-fixed swaps	260		635
Total	$	520	$	1,270

The related AOCI derivative gain for the three and six months ended as of June 30, 2023 was immaterial.

Economic Hedges (Interest Rate and Other Risk)

Exelon Corporate executes derivative instruments to mitigate exposure to fluctuations in interest rates but for which the fair value or cash flow hedge elections were not made. For derivatives intended to serve as economic

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Derivative Financial Instruments

hedges, fair value is recorded on the balance sheet and changes in fair value each period are recognized in earnings or as a regulatory asset or liability, if regulatory requirements are met, each period.

Exelon Corporate enters into floating-to-fixed interest rate cap swaps to manage a portion of interest rate exposure in connection with existing borrowings. In the fourth quarter of 2022, Exelon Corporate entered into $1 billion notional of 18-month maturity floating-to-fixed interest rate cap swaps and $850 million notional of 6-month maturity floating-to-fixed interest rate cap swaps, for a total of $1.85 billion notional of floating-to-fixed interest rate cap swaps as of December 31, 2022. The 6-month maturity floating-to-fixed interest rate cap swaps of $850 million notional matured in March 2023. Exelon receives payments on the interest rate cap when the floating rate exceeds the fixed rate. Settlements received are immaterial as of June 30, 2023.

Additionally, to manage potential fluctuations in Electric operating revenues related to ComEd's distribution formula rate, Exelon Corporate enters into 30-year constant maturity treasury interest rate (Corporate 30-year treasury) swaps.

The following table provides the notional amounts outstanding held by Exelon at June 30, 2023 and December 31, 2022.


Hedging Instrument	June 30, 2023		December 31, 2022
Interest rate cap swaps	$	1,000	$	1,850
Constant maturity treasury interest rate swaps	$	4,875	$	500
Total	$	5,875	$	2,350

For the three and six months ended June 30, 2023, Exelon Corporate recognized the following net pre-tax mark-to-market gains (losses) which are also recognized in Net fair value changes related to derivatives in Exelon's Consolidated Statements of Cash Flows. Exelon had no swaps for the three and six months ended June 30, 2022.


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
Income Statement Location	(Loss) Gain		(Loss) Gain
Electric operating revenues	$	(6)	$	(5)
Interest expense	2		1
Total	$	(4)	$	(4)

Credit Risk

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. 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. The amount of cash collateral received from external counterparties decreased as of June 30, 2023 due to decreasing energy prices. The following table reflects the Registrants' cash collateral held with external counterparties, which is recorded in Other current liabilities on their respective Consolidated Balance Sheets, at June 30, 2023 and December 31, 2022:

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Derivative Financial Instruments


	June 30, 2023		December 31, 2022
Exelon	$	108	$	297
ComEd	102		77
PECO(a)	—		—
BGE	1		23
PHI	6		197
Pepco(b)	—		26
DPL(b)	—		121
ACE	6		50

__________

(a)PECO had less than one million in cash collateral held with external parties at June 30, 2023 and December 31, 2022.

(b)Pepco and DPL had less than one million in cash collateral held with external parties at June 30, 2023.

The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of June 30, 2023, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of June 30, 2023, they could have been required to post collateral to their counterparties of $21 million, $37 million, and $9 million, respectively.

10. 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. PECO meets its 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 borrowings from 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 supported by the revolving credit agreements at June 30, 2023 and December 31, 2022.


	Outstanding Commercial Paper at				Average Interest Rate on Commercial Paper Borrowings at
Commercial Paper Issuer	June 30, 2023		December 31, 2022		June 30, 2023		December 31, 2022
Exelon(a)	$	336	$	1,938	5.23	%	4.77	%
ComEd	297		427		5.22	%	4.71	%
PECO	—		239		—	%	4.71	%
BGE	—		409		—	%	4.81	%
PHI(b)	37		414		5.32	%	4.78	%

Pepco	—		299		—	%	4.79	%
DPL	—		115		—	%	4.76	%
ACE	37		—		5.32	%	—	%

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Debt and Credit Agreements

__________

(a)Exelon Corporate had $2 million and $449 million in outstanding commercial paper borrowings at June 30, 2023 and December 31, 2022, respectively.

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

Revolving Credit Agreements

Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. The following table reflects the credit agreements:


Borrower	Aggregate Bank Commitment		Interest Rate
Exelon Corporate	$	900	SOFR plus 1.275	%
ComEd	1,000		SOFR plus 1.000	%
PECO	600		SOFR plus 0.900	%
BGE	600		SOFR plus 0.900	%
Pepco	300		SOFR plus 1.075	%
DPL	300		SOFR plus 1.000	%
ACE	300		SOFR plus 1.075	%

Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of June 30, 2023.

The Utility Registrants have credit facility agreements, arranged at minority and community banks, which are solely utilized to issue letters of credit. The facility agreements have aggregate commitments of $40 million, $40 million, $15 million, $15 million, $15 million, and $15 million, at ComEd, PECO, BGE, Pepco, DPL, and ACE, respectively. These facilities expire on October 6, 2023.

See Note 16 — Debt and Credit Agreements of the 2022 Form 10-K for additional information on the Registrants' credit facilities.

Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed in the first quarter of 2023 and was bifurcated into two tranches of $300 million on March 14, 2023 and $200 million on March 24, 2023. The agreements will expire on March 14, 2024 and March 22, 2024, respectively. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.90% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.

On October 4, 2022, ComEd entered into a 364-day term loan agreement for $150 million with a variable rate equal to SOFR plus 0.75% and an expiration date of October 3, 2023. The proceeds from this loan were used to repay outstanding commercial paper obligations. The balance of the loan was repaid on January 13, 2023 in conjunction with the $400 million and $575 million First Mortgage Bond agreements that were entered into on January 3, 2023. Refer to the Issuance of Long-Term Debt table below for further information.

On May 9, 2023, ComEd entered into a 364-day term loan agreement for $400 million with a variable rate equal to SOFR plus 1.00% and an expiration date of May 7, 2024. The proceeds from this loan were used to repay outstanding commercial paper obligations and for general corporate purposes. The loan agreement is reflected in Exelon's and ComEd's Consolidated Balance Sheets within Short-term borrowings.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Debt and Credit Agreements

Long-Term Debt

Issuance of Long-Term Debt

During the six months ended June 30, 2023, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Notes

5.15%

March 15, 2028

$1,000

Repay existing indebtedness and for general corporate purposes.

Exelon

Notes

5.30%

March 15, 2033

850

Repay existing indebtedness and for general corporate purposes.

Exelon

Notes

5.60%

March 15, 2053

650

Repay existing indebtedness and for general corporate purposes.

ComEd

First Mortgage Bonds, Series 134

4.90%

February 1, 2033

400

Repay outstanding commercial paper obligations and to fund other general corporate purposes.

ComEd

First Mortgage Bonds Series 135

5.30%

February 1, 2053

575

Repay outstanding commercial paper obligations and to fund other general corporate purposes.

PECO

First and Refunding Mortgage Bonds

4.90%

June 15, 2033

575

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

BGE

Notes

5.40%

June 1, 2053

700

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

Pepco(a)

First Mortgage Bonds

5.30%

March 15, 2033

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.40%

March 15, 2038

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.57%

March 15, 2053

125

Repay existing indebtedness and for general corporate purposes.

DPL(b)

First Mortgage Bonds

5.30%

March 15, 2033

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

5.57%

March 15, 2053

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

5.57%

March 15, 2053

Repay existing indebtedness and for general corporate purposes.

__________

(a)On March 15, 2023, Pepco entered into a purchase agreement of First Mortgage Bonds of $100 million at 5.35% due on September 13, 2033. The closing date of the issuance is expected to occur in September 2023.

(b)On March 15, 2023, DPL entered into a purchase agreement of First Mortgage Bonds of $340 million, $75 million, and $110 million at 5.45%, 5.55% and 5.72% due on November 8, 2033, November 8, 2038, and November 8, 2053, respectively. The closing date of the issuance is expected to occur in November 2023.

Debt Covenants

As of June 30, 2023, the Registrants are in compliance with debt covenants.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

11. 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, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of June 30, 2023 and December 31, 2022. The Registrants have no financial liabilities classified as Level 1 or measured using the NAV practical expedient.

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


	June 30, 2023								December 31, 2022
	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	$	40,997	$	33,514	$	2,752	$	36,266	$	37,074	$	29,902	$	2,327	$	32,229
ComEd	11,482		10,015		—		10,015		10,518		9,006		—		9,006
PECO	5,132		4,426		—		4,426		4,612		3,864		50		3,914
BGE	4,601		4,029		—		4,029		4,207		3,613		—		3,613
PHI	8,550		4,535		2,752		7,287		8,120		4,507		2,277		6,784
Pepco	3,998		2,240		1,469		3,709		3,751		2,229		1,205		3,434
DPL	2,061		1,168		589		1,757		1,938		1,164		458		1,622
ACE	1,834		914		694		1,608		1,757		909		614		1,523
Long-Term Debt to Financing Trusts
Exelon	$	390	$	—	$	392	$	392	$	390	$	—	$	384	$	384
ComEd	205		—		207		207		205		—		204		204
PECO	184		—		185		185		184		—		180		180

__________

(a)Includes unamortized debt issuance costs, unamortized debt discount and premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are not fair valued. Refer to Note 16 — Debt and Credit Agreements of the 2022 Form 10-K for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 10 — Leases of the 2022 Form 10-K for finance lease liabilities.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — 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 at June 30, 2023 and December 31, 2022. The Registrants have no financial assets or liabilities measured using the NAV practical expedient:

Exelon


	At June 30, 2023						At December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	702	$	—	$	—	$	702	$	664	$	—	$	—	$	664
Rabbi trust investments
Cash equivalents	66		—		—		66		62		—		—		62
Mutual funds	50		—		—		50		49		—		—		49
Fixed income	—		7		—		7		—		7		—		7
Life insurance contracts	—		58		42		100		—		58		40		98
Rabbi trust investments subtotal	116		65		42		223		111		65		40		216

Interest rate derivative assets
Derivatives designated as hedging instruments	—		12		—		12		—		6		—		6
Economic hedges	—		5		—		5		—		5		—		5
Interest rate derivative assets subtotal	—		17		—		17		—		11		—		11
Total assets	818		82		42		942		775		76		40		891
Liabilities
Commodity derivative liabilities	—		—		(133)		(133)		—		—		(84)		(84)
Interest rate derivative liabilities
Derivatives designated as hedging instruments	—		—		—		—		—		(4)		—		(4)
Economic hedges	—		(7)		—		(7)		—		(3)		—		(3)
Interest rate derivative liabilities subtotal	—		(7)		—		(7)		—		(7)		—		(7)
Deferred compensation obligation	—		(74)		—		(74)		—		(75)		—		(75)
Total liabilities	—		(81)		(133)		(214)		—		(82)		(84)		(166)
Total net assets (liabilities)	$	818	$	1	$	(91)	$	728	$	775	$	(6)	$	(44)	$	725

__________

(a)Exelon excludes cash of $225 million and $345 million at June 30, 2023 and December 31, 2022, respectively, and restricted cash of $108 million and $81 million at June 30, 2023 and December 31, 2022, respectively, and includes long-term restricted cash of $201 million and $117 million at June 30, 2023 and December 31, 2022, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

ComEd, PECO, and BGE


	ComEd								PECO								BGE
At June 30, 2023	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)	$	484	$	—	$	—	$	484	$	69	$	—	$	—	$	69	$	76	$	—	$	—	$	76
Rabbi trust investments

Mutual funds	—		—		—		—		9		—		—		9		9		—		—		9
Life insurance contracts	—		—		—		—		—		16		—		16		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		9		16		—		25		9		—		—		9

Total assets	484		—		—		484		78		16		—		94		85		—		—		85
Liabilities
Commodity derivative liabilities(b)	—		—		(133)		(133)		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		(7)		—		(7)		—		(8)		—		(8)		—		(4)		—		(4)
Total liabilities	—		(7)		(133)		(140)		—		(8)		—		(8)		—		(4)		—		(4)
Total net assets (liabilities)	$	484	$	(7)	$	(133)	$	344	$	78	$	8	$	—	$	86	$	85	$	(4)	$	—	$	81


	ComEd								PECO								BGE
At December 31, 2022	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)	$	392	$	—	$	—	$	392	$	10	$	—	$	—	$	10	$	23	$	—	$	—	$	23
Rabbi trust investments
Mutual funds	—		—		—		—		7		—		—		7		7		—		—		7
Life insurance contracts	—		—		—		—		—		15		—		15		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		7		15		—		22		7		—		—		7
Total assets	392		—		—		392		17		15		—		32		30		—		—		30
Liabilities
Commodity derivative liabilities(b)	—		—		(84)		(84)		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		(8)		—		(8)		—		(7)		—		(7)		—		(4)		—		(4)
Total liabilities	—		(8)		(84)		(92)		—		(7)		—		(7)		—		(4)		—		(4)
Total net assets (liabilities)	$	392	$	(8)	$	(84)	$	300	$	17	$	8	$	—	$	25	$	30	$	(4)	$	—	$	26

__________

(a)ComEd excludes cash of $50 million and $42 million at June 30, 2023 and December 31, 2022, respectively, and restricted cash of $102 million and $77 million at June 30, 2023 and December 31, 2022, respectively. Additionally, ComEd includes long-term restricted cash of $201 million and $117 million at June 30, 2023 and December 31, 2022, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO excludes cash of $22 million and $58 million at June 30, 2023 and December 31, 2022, respectively. BGE excludes cash of $13 million and $43 million at June 30, 2023 and December 31, 2022, respectively, and restricted cash of $1 million and $1 million at June 30, 2023 and December 31, 2022, respectively.

(b)The Level 3 balance consists of the current and noncurrent liability of $24 million and $109 million, respectively, at June 30, 2023 and $5 million and $79 million, respectively, at December 31, 2022 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL, and ACE


	At June 30, 2023								At December 31, 2022
PHI	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	30	$	—	$	—	$	30	$	205	$	—	$	—	$	205
Rabbi trust investments
Cash equivalents	63		—		—		63		59		—		—		59
Mutual funds	9		—		—		9		11		—		—		11
Fixed income	—		7		—		7		—		7		—		7
Life insurance contracts	—		20		42		62		—		22		39		61
Rabbi trust investments subtotal	72		27		42		141		70		29		39		138
Total assets	102		27		42		171		275		29		39		343
Liabilities
Deferred compensation obligation	—		(13)		—		(13)		—		(14)		—		(14)



Total liabilities	—		(13)		—		(13)		—		(14)		—		(14)
Total net assets	$	102	$	14	$	42	$	158	$	275	$	15	$	39	$	329


	Pepco								DPL								ACE
At June 30, 2023	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)	$	22	$	—	$	—	$	22	$	—	$	—	$	—	$	—	$	1	$	—	$	—	$	1




Rabbi trust investments
Cash equivalents	62		—		—		62		—		—		—		—		—		—		—		—

Life insurance contracts	—		20		42		62		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	62		20		42		124		—		—		—		—		—		—		—		—
Total assets	84		20		42		146		—		—		—		—		1		—		—		1
Liabilities
Deferred compensation obligation	—		(1)		—		(1)		—		—		—		—		—		—		—		—



Total liabilities	—		(1)		—		(1)		—		—		—		—		—		—		—		—
Total net assets	$	84	$	19	$	42	$	145	$	—	$	—	$	—	$	—	$	1	$	—	$	—	$	1

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities


	Pepco								DPL								ACE
At December 31, 2022	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)	$	51	$	—	$	—	$	51	$	121	$	—	$	—	$	121	$	1	$	—	$	—	$	1
Rabbi trust investments
Cash equivalents	59		—		—		59		—		—		—		—		—		—		—		—


Life insurance contracts	—		22		38		60		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	59		22		38		119		—		—		—		—		—		—		—		—
Total assets	110		22		38		170		121		—		—		121		1		—		—		1
Liabilities
Deferred compensation obligation	—		(1)		—		(1)		—		—		—		—		—		—		—		—



Total liabilities	—		(1)		—		(1)		—		—		—		—		—		—		—		—
Total net assets	$	110	$	21	$	38	$	169	$	121	$	—	$	—	$	121	$	1	$	—	$	—	$	1

__________

(a)PHI excludes cash of $101 million and $165 million at June 30, 2023 and December 31, 2022, respectively, and restricted cash of $5 million and $3 million at June 30, 2023 and December 31, 2022, respectively. Pepco excludes cash of $15 million and $45 million at June 30, 2023 and December 31, 2022, respectively, and restricted cash of $5 million and $3 million at June 30, 2023 and December 31, 2022, respectively. DPL excludes cash of $18 million and $31 million at June 30, 2023 and December 31, 2022, respectively. ACE excludes cash of $23 million and $71 million at June 30, 2023 and December 31, 2022, respectively.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

Reconciliation of Level 3 Assets and Liabilities

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2023 and 2022:



	Exelon		ComEd			PHI and Pepco
Three Months Ended June 30, 2023	Total		Commodity Derivatives			Life Insurance Contracts
Balance at March 31, 2023	$	(57)	$	(98)		$	41
Total realized / unrealized gains (losses)
Included in net income(a)	1		—			1


Included in regulatory assets/liabilities	(35)		(35)		(b)	—








Balance at June 30, 2023	$	(91)	$	(133)	(c)	$	42
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2023	$	1	$	—		$	1



	Exelon		ComEd			PHI and Pepco
Three Months Ended June 30, 2022	Total		Commodity Derivatives			Life Insurance Contracts
Balance at March 31, 2022	$	(107)	$	(144)		$	36
Total realized / unrealized gains (losses)
Included in net income(a)	1		—			1

Included in regulatory assets/liabilities	56		56		(b)	—








Balance at June 30, 2022	$	(50)	$	(88)	(c)	$	37
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2022	$	1	$	—		$	1


	Exelon		ComEd			PHI and Pepco
Six Months Ended June 30, 2023	Total		Commodity Derivatives			Life Insurance Contracts
Balance at December 31, 2022	$	(44)	$	(84)		$	40
Total realized / unrealized gains (losses)
Included in net income(a)	2		—			2


Included in regulatory assets/liabilities	(49)		(49)		(b)	—








Balance at June 30, 2023	$	(91)	$	(133)	(c)	$	42
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at June 30, 2023	$	2	$	—		$	2


	Exelon		ComEd			PHI and Pepco
Six Months Ended June 30, 2022	Total		Commodity Derivatives			Life Insurance Contracts
Balance at December 31, 2021	$	(182)	$	(219)		$	35
Total realized / unrealized gains (losses)
Included in net income(a)	2		—			2


Included in regulatory assets/liabilities	131		131		(b)	—







Transfers out of Level 3	(1)		—			—
Balance at June 30, 2022	$	(50)	$	(88)	(c)	$	37
The amount of total gains included in income attributed to the change in unrealized gain related to assets and liabilities at June 30, 2022	$	2	$	—		$	2

__________

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

(a)Classified in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.

(b)Includes $43 million of decreases in fair value and an increase for realized gains due to settlements of $8 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2023. Includes $59 million of increases in fair value and a decrease for realized losses due to settlements of $3 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2022. Includes $68 million of decreases in fair value and an increase for realized losses due to settlements of $19 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2023. Includes $128 million of increases in fair value and an increase for realized losses due to settlements of $3 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2022.

(c)The balance consists of a current and noncurrent liability of $24 million and $109 million, respectively, at June 30, 2023. The balance consists of $15 million of current assets and current and noncurrent liability of none and $103 million, respectively at June 30, 2022.

Valuation Techniques Used to Determine Fair Value

Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of the 2022 Form 10-K.

Commodity Derivatives (Exelon and ComEd)

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


Type of trade	Fair Value at June 30, 2023		Fair Value at December 31, 2022		Valuation Technique	Unobservable Input	2023 Range & Arithmetic Average				2022 Range & Arithmetic Average
Commodity derivatives	$	(133)	$	(84)	Discounted Cash Flow	Forward power price(a)	$25.56	-	$75.64	$43.03	$34.78	-	$75.71	$48.44

________

(a)An increase to the forward power price would increase the fair value.

12. Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 18 — Commitments and Contingencies of the 2022 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 at June 30, 2023:


Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments(a)	44		40		35		3		2

__________

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

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Note 12 — Commitments and Contingencies

Commercial Commitments (All Registrants). The Registrants’ commercial commitments at June 30, 2023, representing commitments potentially triggered by future events were as follows:


			Expiration within
	Total		2023		2024		2025		2026		2027		2028 and beyond
Exelon
Letters of credit	$	21	$	13	$	8	$	—	$	—	$	—	$	—
Surety bonds(a)	206		172		34		—		—		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values(b)	29		—		4		6		5		4		10
Total commercial commitments	$	634	$	185	$	46	$	6	$	5	$	4	$	388

ComEd
Letters of credit	$	12	$	9	$	3	$	—	$	—	$	—	$	—
Surety bonds(a)	46		39		7		—		—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	258	$	48	$	10	$	—	$	—	$	—	$	200

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

BGE
Letters of credit	$	4	$	2	$	2	$	—	$	—	$	—	$	—
Surety bonds(a)	3		1		2		—		—		—		—
Total commercial commitments	$	7	$	3	$	4	$	—	$	—	$	—	$	—

PHI

Surety bonds(a)	$	97	$	77	$	20	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	29		—		4		6		5		4		10
Total commercial commitments	$	126	$	77	$	24	$	6	$	5	$	4	$	10

Pepco

Surety bonds(a)	$	85	$	71	$	14	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	10		—		1		3		2		1		3
Total commercial commitments	$	95	$	71	$	15	$	3	$	2	$	1	$	3

DPL

Surety bonds(a)	$	7	$	3	$	4	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	12		—		2		2		2		2		4
Total commercial commitments	$	19	$	3	$	6	$	2	$	2	$	2	$	4

ACE
Surety bonds(a)	$	5	$	3	$	2	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	7		—		1		1		1		1		3
Total commercial commitments	$	12	$	3	$	3	$	1	$	1	$	1	$	3

__________

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

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Note 12 — 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 9 years. The maximum potential obligation at the end of the minimum lease term would be $65 million guaranteed by Exelon and PHI, of which $22 million, $27 million, and $16 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 (All 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 some sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

•ComEd has 19 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 2031.

•PECO has 6 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 2024.

•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 2025.

•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 a PAPUC order, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.

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Note 12 — Commitments and Contingencies

At June 30, 2023 and December 31, 2022, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Accrued expenses, Other current liabilities, and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:


	June 30, 2023				December 31, 2022
	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	$	423	$	334	$	409	$	355
ComEd	304		303		325		324
PECO	24		23		25		23
BGE	9		8		9		8
PHI	82		—		46		—
Pepco	80		—		44		—
DPL	1		—		1		—
ACE	1		—		1		—

Benning Road Site (Exelon, 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, which is owned by Pepco, was formerly the location of an electric generating facility owned by Pepco subsidiary, Pepco Energy Services (PES), which became a part of Generation, following the 2016 merger between PHI and Exelon. This generating facility 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 (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco Entities to conduct a Remedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.

Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which DOEE approved on February 3, 2020. The Pepco Entities are completing a FS to evaluate possible remedial alternatives for submission to DOEE. In October 2022, DOEE approved dividing the work to complete the landside portion of the FS from the waterside portion to expedite the overall schedule for completion of the project. After completion and approval of the landside FS, now scheduled for December 31, 2023, DOEE will prepare a Proposed Plan for public comment and then issue a Record of Decision (ROD) identifying any further response actions determined to be necessary to address any landside issues. The DOEE will issue a separate ROD for the waterside FS when that work is completed which is now anticipated to be by March 31, 2024.

As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Generation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. Exelon, PHI, and Pepco 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 the Pepco Entities, DOEE and NPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by the Pepco Entities 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.

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Note 12 — Commitments and Contingencies

On September 30, 2020, DOEE released its Interim ROD. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion.

On July 15, 2022, Pepco received a letter from the District of Columbia's Office of the Attorney General (D.C. OAG) on behalf of DOEE conveying a settlement offer to resolve all PRPs' liability to the District of Columbia (District) for their past costs and their anticipated future costs to complete the work for the Interim ROD. Pepco responded on July 27, 2022 to enter into settlement discussions. Since that time Exelon and the other PRPs at the site have exchanged letters with the D.C. OAG exploring potential settlement options. Those discussions are ongoing. Exelon, PHI, and Pepco have determined that it is probable that costs for remediation will be incurred and have accrued a liability for management's best estimate of its share of the costs. 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 NRD assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has entered into negotiations with the Trustees to evaluate possible incorporation of NRD assessment and restoration as part of its remedial activities associated with the Benning site to accelerate the NRD benefits for that portion of the Anacostia River Sediment Project (ARSP) assessment. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the NRD process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process.

As noted in the Benning Road Site disclosure above, as part of the separation of Exelon and Constellation in February 2022, an assumption agreement was executed transferring any potential future remediation liabilities associated with the Benning Site remediation to a non-utility subsidiary of Exelon. Similarly, any potential future liability associated with the ARSP was also assumed by this entity.

Buzzard Point Site (Exelon, PHI, and Pepco). On December 8, 2022, Pepco received a letter from the D.C. OAG, alleging wholly past violations of the District's stormwater discharge and waste disposal requirements related to operations at the Buzzard Point facility, a 9-acre parcel of waterfront property in Washington, D.C. occupied by an active substation and former steam plant building. The letter also alleged wholly past violations by Pepco of stormwater discharge requirements related to its district-wide system of underground vaults. The D.C. OAG invited Pepco to resolve the threatened enforcement action through a court-approved consent decree, and Pepco is engaged in discussions with the D.C. OAG regarding a potential resolution. Exelon, PHI, and Pepco have determined that a loss associated with this matter is probable and have accrued an estimated liability. Pepco concluded that incremental exposure is reasonably possible, but the range of loss cannot be reasonably estimated beyond the amounts included in the table above.

Litigation and Regulatory Matters

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 former 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

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Note 12 — Commitments and Contingencies

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 three-year term of the DPA ended on July 17, 2023, and on that same date the court granted the USAO’s motion to dismiss the pending charge that had been deferred by the DPA.

The SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the SEC. In the second quarter of 2023, a loss contingency of $46.2 million was recorded in Operating and maintenance expense within Exelon's Consolidated Statements of Operations and Comprehensive Income and in Accrued expenses on the Consolidated Balance Sheets.

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:

•Four putative class action lawsuits against ComEd and Exelon were filed in federal court on behalf of ComEd customers in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, the Citizens Utility Board (CUB) filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. On September 9, 2021, the federal court granted Exelon’s and ComEd’s motion to dismiss and dismissed the plaintiffs’ and CUB’s federal law claim with prejudice. The federal court also dismissed the related state law claims made by the federal plaintiffs and CUB on jurisdictional grounds. Plaintiffs appealed dismissal of the federal law claim to the Seventh Circuit Court of Appeals. Plaintiffs and CUB also refiled their state law claims in state court and moved to consolidate them with the already pending consumer state court class action, discussed below. On August 22, 2022, the Seventh Circuit affirmed the dismissal of the consolidated federal cases in their entirety. The time to further appeal has passed and the Seventh Circuit’s decision is final.

•Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. The cases were consolidated into a single action in October of 2020. In November 2020, CUB filed a motion to intervene in the cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied CUB's request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion was completed on March 2, 2021. The parties agreed, on March 25, 2021, along with the federal court plaintiffs discussed above, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On December 23, 2021, the state court granted ComEd and Exelon's motion to dismiss with prejudice. On December 30, 2021, plaintiffs filed a motion to reconsider that dismissal and for permission to amend their complaint. The court denied the plaintiffs' motion on January 21, 2022. Plaintiffs have appealed the court's ruling dismissing their complaint to the First District Court of Appeals. On February 15, 2022, Exelon and ComEd moved to dismiss the federal plaintiffs' refiled state law claims, seeking dismissal on the same legal grounds asserted in their motion to dismiss the original state court plaintiffs' complaint. The court granted dismissal of the refiled state claims on February 16, 2022. The original federal plaintiffs appealed that dismissal on February 18, 2022. The two state appeals were consolidated on March 21, 2022. The appellate briefing is complete and the parties are awaiting oral argument and/or a decision.

•On November 3, 2022, a plaintiff filed a putative class action complaint in Lake County, Illinois Circuit Court against ComEd and Exelon for unjust enrichment and deceptive business practices in connection with the conduct giving rise to the DPA. Plaintiff seeks an accounting and disgorgement of any benefits ComEd allegedly obtained from said conduct. Plaintiff served initial discovery requests on ComEd in December 2022, to which ComEd has responded. ComEd and Exelon filed a motion to dismiss the Complaint on February 3, 2023. On June 16, 2023, the court granted Exelon and ComEd's motion to dismiss the action with prejudice. Plaintiff filed its notice of appeal of that dismissal on July 17, 2023.

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Note 12 — Commitments and Contingencies

•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. The court denied the motion in April 2021. On May 26, 2021, defendants moved the court to certify its order denying the motion to dismiss for interlocutory appeal. Briefing on the motion was completed in June 2021. That motion was denied on January 28, 2022. In May 2021, the parties each filed respective initial discovery disclosures. On June 9, 2021, defendants filed their answer and affirmative defenses to the complaint and the parties engaged thereafter in discovery. On September 9, 2021, the U.S. government moved to intervene in the lawsuit and stay discovery until the parties entered into an amendment to their protective order that would prohibit the parties from requesting discovery into certain matters, including communications with the U.S. government. The court ordered said amendment to the protective order on November 15, 2021 and discovery resumed. The court further amended the protective order on October 17, 2022 and extended it until May 15, 2023. Following mediation, the parties reached a settlement of the lawsuit, under which defendants agreed to pay plaintiffs $173 million. On May 26, 2023, plaintiffs filed a motion for preliminary approval of the settlement, which the court granted on June 9, 2023. The court set a hearing for final approval of the settlement, which will follow a class notice period, for September 7, 2023. The settlement was fully covered by insurance and has been paid in full.

•Several shareholders have sent letters to the Exelon Board of Directors since 2020 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (SLC) consisting of disinterested and independent parties to investigate and address these shareholders’ allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC’s investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. On October 12, 2021, the parties to the derivative action filed an agreed motion to stay that litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The stay has been extended several times. The parties participated in a mediation in February 2023 and efforts to resolve the matter remain ongoing. On April 26 and May 1, 2023, two additional demand letter shareholders each filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and certain third parties, and against Exelon as nominal defendant, asserting claims similar to those made in their respective demand letters. On May 25, 2023, certain demand letter shareholders (Settling Shareholders) filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and against Exelon as nominal defendant, asserting claims similar to those made in their respective demand letters. All pending derivative lawsuits were consolidated.

•On May 26, 2023, prior to lawsuit consolidation, the SLC filed a Notice of Determination and Intent to Seek Court Approval of Settlement (Notice of Determination). The Notice of Determination stated that, through mediation efforts, a settlement of the derivative claims had been approved by the SLC, the Independent Review Committee of the Board (which had been formed in the third quarter of 2022, to ensure the Board’s consideration of any SLC recommendations would be independent and objective), the Board, and the Settling Shareholders (the Settling Parties). The Notice of Determination further specified the process by which the Settling Parties would seek court approval of the proposed settlement and resolution and dismissal of all derivative claims and lawsuits, including any lawsuits or actions brought by demand letter shareholders who are not participating in the proposed settlement. In furtherance of the proposed settlement, on June 16, 2023, the SLC filed a motion for preliminary approval of the settlement, attaching the Stipulation and Agreement of Settlement (Stipulation), which contains the terms of the proposed settlement. The proposed settlement terms include but are not limited to: a payment of $40 million to Exelon by Exelon’s insurers of which $10 million constitutes the attorneys’ fee award to be paid to the Settling Shareholders’ counsel; various compliance and disclosure-related reforms; and certain changes in Board and Committee composition. On June 13, 2023, the non-settling derivative shareholders filed a motion asking the court to set a status conference to discuss lifting the discovery stay. On June 29, 2023, an additional shareholder filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and against

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Note 12 — Commitments and Contingencies

Exelon as nominal defendant, asserting claims similar to those made in its demand letter. On June 30, 2023, the non-settling shareholders’ motion for status and the SLC’s motion for preliminary approval was heard by the court, during which the court set a briefing schedule on the appropriate standard for evaluating the settlement and the proper scope of requested discovery. The parties simultaneously filed opening briefs on July 21, 2023 and filed opposition briefs on August 1, 2023. A hearing is set for August 14, 2023.

•Several shareholders have sent requests seeking review of certain Exelon books and records since August 2021. Exelon has responded to each request.

In August 2022, the ICC concluded its investigation initiated on August 12, 2021 into rate impacts of conduct admitted in the DPA, including the costs recovered from customers related to the DPA and Exelon's funding of the fine paid by ComEd. On August 17, 2022, the ICC issued its final order accepting ComEd's voluntary customer refund offer of approximately $38 million (of which about $31 million is ICC jurisdictional; the remaining balance is FERC jurisdictional) that resolves the question of whether customer funds were used for DPA related activities. The customer refund includes the cost of every individual or entity that was either (i) identified in the DPA or (ii) identified by ComEd as an associate of the former Speaker of the Illinois House of Representatives in the ICC proceeding. The ICC’s DPA investigation is now closed. The ICC jurisdictional refund was made to customers during the April 2023 billing cycle, as required by the ICC. The FERC jurisdictional refund is being made as part of ComEd's transmission formula rate update proceeding, filed on May 12, 2023. The filed transmission rate, inclusive of the FERC jurisdictional DPA refund, will appear on ComEd retail customers' bills for the June 2023 through May 2024 monthly billing periods, in the line designated as "Transmission Services Charge." The customer refund will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. An accrual for the amount of the customer refund has been recorded in Regulatory assets in Exelon’s and ComEd’s Consolidated Balance Sheets as of June 30, 2023.

Savings Plan Claim (Exelon). On December 6, 2021, seven current and former employees filed a putative ERISA class action suit in U.S. District Court for the Northern District of Illinois against Exelon, its Board of Directors, the former Board Investment Oversight Committee, the Corporate Investment Committee, individual defendants, and other unnamed fiduciaries of the Exelon Corporation Employee Savings Plan (Plan). The complaint alleges that the defendants violated their fiduciary duties under the Plan by including certain investment options that allegedly were more expensive than and underperformed similar passively-managed or other funds available in the marketplace and permitting a third-party administrative service provider/recordkeeper and an investment adviser to charge excessive fees for the services provided. The plaintiffs seek declaratory, equitable and monetary relief on behalf of the Plan and participants. On February 16, 2022, the court granted the parties' stipulated dismissal of the individual named defendants without prejudice. The remaining defendants filed a motion to dismiss the complaint on February 25, 2022. On March 4, 2022, the Chamber of Commerce filed a brief of amicus curiae in support of the defendants' motion to dismiss. On September 22, 2022, the court granted Exelon’s motion to dismiss without prejudice. The court granted plaintiffs leave until October 31, 2022 to file an amended complaint, which was later extended to November 30, 2022. Plaintiffs filed their amended complaint on November 30, 2022. Defendants filed their motion to dismiss the amended complaint on January 20, 2023. Briefing on the motion to dismiss is now complete and the parties await a ruling. No loss contingencies have been reflected in Exelon’s consolidated financial statements with respect to this matter, as such contingencies are neither probable nor reasonably estimable at this time.

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 Registrants are also from time to time subject to audits and investigations by the FERC and other regulators. 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.

13. Shareholders' Equity (Exelon)

At-the-Market (ATM) Program

On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common Stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of Common Stock under the Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the Equity Distribution Agreement. As of June 30, 2023, Exelon has not issued any shares of Common Stock under the ATM program and has not entered into any forward sale agreements.

14. Changes in Accumulated Other Comprehensive Income (Loss) (Exelon)

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


Three Months Ended June 30, 2023	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Balance at March 31, 2023	$	8	$	(647)	$	—	$	(639)
OCI before reclassifications	9		(3)		—		6
Amounts reclassified from AOCI	—		3		—		3
Net current-period OCI	9		—		—		9
Balance at June 30, 2023	$	17	$	(647)	$	—	$	(630)


Three Months Ended June 30, 2022	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Balance at March 31, 2022	$	—	$	(713)	$	—	$	(713)
OCI before reclassifications	—		2		—		2
Amounts reclassified from AOCI	—		10		—		10
Net current-period OCI	—		12		—		12
Balance at June 30, 2022	$	—	$	(701)	$	—	$	(701)


Six Months Ended June 30, 2023	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Balance at December 31, 2022	$	2	$	(640)	$	—	$	(638)
OCI before reclassifications	15		(13)		—		2
Amounts reclassified from AOCI	—		6		—		6
Net current-period OCI	15		(7)		—		8
Balance at June 30, 2023	$	17	$	(647)	$	—	$	(630)

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Changes in Accumulated Other Comprehensive Income


Six Months Ended June 30, 2022	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Balance at December 31, 2021	$	(6)	$	(2,721)	$	(23)	$	(2,750)
Separation of Constellation	6		1,994		23		2,023
OCI before reclassifications	—		2		—		2
Amounts reclassified from AOCI	—		24		—		24
Net current-period OCI	—		26		—		26
Balance at June 30, 2022	$	—	$	(701)	$	—	$	(701)

__________

(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. Additionally, as of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. See Note 14 — Retirement Benefits of the 2022 Form 10-K and Note 8 — 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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Pension and non-pension postretirement benefit plans:

Actuarial loss reclassified to periodic benefit cost	$	(1)	$	(3)	$	(2)	$	(8)
Pension and non-pension postretirement benefit plans valuation adjustment	1		(1)		4		—
Unrealized gain on cash flow hedges	(3)		—		(4)		—

15. 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:

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Supplemental Financial Information


	Taxes other than income taxes
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended June 30, 2023
Utility taxes(a)	$	201	$	71	$	38	$	22	$	70	$	63	$	6	$	1
Property	96		8		4		49		35		24		10		1
Payroll	31		7		4		5		7		2		1		1

Three Months Ended June 30, 2022
Utility taxes(a)	$	203	$	71	$	39	$	20	$	73	$	67	$	5	$	1
Property	94		10		4		46		33		23		10		—
Payroll	28		7		5		4		7		1		1		1

Six Months Ended June 30, 2023
Utility taxes(a)	$	421	$	146	$	78	$	50	$	147	$	131	$	14	$	2
Property	196		18		8		100		70		48		21		1
Payroll	63		14		9		9		14		4		2		2

Six Months Ended June 30, 2022
Utility taxes(a)	$	424	$	149	$	77	$	47	$	151	$	137	$	12	$	2
Property	188		20		9		92		67		46		20		1
Payroll	64		13		8		9		14		3		2		2

_________

(a)The Registrants' utility taxes represent 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.


	Other, Net
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended June 30, 2023
AFUDC — Equity	$	34	$	7	$	6	$	4	$	17	$	13	$	2	$	2
Non-service net periodic benefit credit	(1)		—		—		—		—		—		—		—

Three Months Ended June 30, 2022
AFUDC — Equity	$	38	$	9	$	8	$	6	$	15	$	11	$	2	$	2
Non-service net periodic benefit cost	16		—		—		—		—		—		—		—

Six Months Ended June 30, 2023
AFUDC — Equity	$	71	$	17	$	12	$	7	$	35	$	27	$	4	$	4
Non-service net periodic benefit credit	(2)		—		—		—		—		—		—		—

Six Months Ended June 30, 2022
AFUDC — Equity	$	74	$	17	$	15	$	12	$	30	$	22	$	4	$	4
Non-service net periodic benefit cost	33		—		—		—		—		—		—		—

Supplemental Cash Flow Information

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

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Supplemental Financial Information


	Depreciation, amortization, and accretion
	Exelon(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Six Months Ended June 30, 2023
Property, plant, and equipment(b)	$	1,370	$	540	$	190	$	249	$	364	$	152	$	104	$	96
Amortization of regulatory assets(b)	352		148		7		76		120		64		17		39
Amortization of intangible assets, net(b)	4		—		—		—		—		—		—		—


ARO accretion(e)	1		—		—		—		—		—		—		—
Total depreciation and amortization	$	1,727	$	688	$	197	$	325	$	484	$	216	$	121	$	135

Six Months Ended June 30, 2022
Property, plant, and equipment(b)	$	1,376	$	511	$	177	$	235	$	335	$	145	$	92	$	83
Amortization of regulatory assets(b)	357		138		8		87		124		68		21		35
Amortization of intangible assets, net(b)	8		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(c)	3		—		—		—		—		—		—		—
Nuclear fuel(d)	66		—		—		—		—		—		—		—
ARO accretion(e)	44		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	1,854	$	649	$	185	$	322	$	459	$	213	$	113	$	118

__________

(a)Exelon's 2022 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

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

(c)Included in Electric operating revenues or Purchased power expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income.

(d)Included in Purchased fuel expense in Exelon's Consolidated Statement of Operations and Comprehensive Income.

(e)Included in Operating and maintenance expense in Exelon's Consolidated Statement of Operations and Comprehensive Income.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Supplemental Financial Information


	Other non-cash operating activities
	Exelon(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Six Months Ended June 30, 2023
Pension and OPEB costs (benefit)	$	89	$	13	$	(7)	$	28	$	49	$	17	$	9	$	7
Allowance for credit losses	46		1		19		4		22		13		3		6


True-up adjustments to decoupling mechanisms and formula rates(b)	(410)		(270)		10		(70)		(80)		(46)		(15)		(19)


Long-term incentive plan	13		—		—		—		—		—		—		—


Amortization of operating ROU asset	19		1		—		2		14		2		4		2
Change in environmental liabilities	37		—		—		—		37		37		—		—

AFUDC — Equity	(71)		(17)		(12)		(7)		(35)		(27)		(4)		(4)

Six Months Ended June 30, 2022
Pension and OPEB costs (benefit)	$	86	$	30	$	(4)	$	22	$	26	$	4	$	2	$	6
Allowance for credit losses	96		29		21		18		29		16		6		7
Other decommissioning-related activity	36		—		—		—		—		—		—		—
Energy-related options	60		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(b)	(27)		(75)		(6)		32		22		7		3		12


Long-term incentive plan	40		—		—		—		—		—		—		—


Amortization of operating ROU asset	38		1		—		14		14		4		4		2


AFUDC — Equity	(74)		(17)		(15)		(12)		(30)		(22)		(4)		(4)

__________

(a)Exelon's 2022 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

(b)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 PECO, reflects the change in regulatory assets and liabilities associated with its transmission formula rates. For BGE, Pepco, DPL, and ACE, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 3 — Regulatory Matters of the 2022 Form 10-K for additional information.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — 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		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2023
Cash and cash equivalents	$	399	$	74	$	82	$	89	$	110	$	16	$	18	$	24
Restricted cash and cash equivalents	435		361		9		1		26		26		—		—
Restricted cash included in other deferred debits and other assets	201		201		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,035	$	636	$	91	$	90	$	136	$	42	$	18	$	24

December 31, 2022
Cash and cash equivalents	$	407	$	67	$	59	$	43	$	198	$	45	$	31	$	72
Restricted cash and cash equivalents	566		327		9		24		175		54		121		—
Restricted cash included in other deferred debits and other assets	117		117		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,090	$	511	$	68	$	67	$	373	$	99	$	152	$	72

June 30, 2022
Cash and cash equivalents	$	816	$	120	$	23	$	354	$	278	$	14	$	26	$	233
Restricted cash and cash equivalents	961		384		9		205		341		117		223		—
Restricted cash included in other deferred debits and other assets	59		59		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,836	$	563	$	32	$	559	$	619	$	131	$	249	$	233

December 31, 2021
Cash and cash equivalents	$	672	$	131	$	36	$	51	$	136	$	34	$	28	$	29
Restricted cash and cash equivalents	321		210		8		4		77		34		43		—
Restricted cash included in other deferred debits and other assets	44		43		—		—		—		—		—		—
Cash, restricted cash, and cash equivalents from discontinued operations	582		—		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,619	$	384	$	44	$	55	$	213	$	68	$	71	$	29

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2022 Form 10-K.

Supplemental Balance Sheet Information

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

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Supplemental Financial Information


	Accrued expenses
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2023
Compensation-related accruals(a)	$	467	$	121	$	65	$	59	$	88	$	26	$	17	$	14
Taxes accrued	179		101		40		33		75		52		13		8
Interest accrued	423		151		48		43		69		37		12		15


December 31, 2022
Compensation-related accruals(a)	$	613	$	179	$	81	$	79	$	104	$	29	$	20	$	16
Taxes accrued	211		92		10		34		70		52		8		12
Interest accrued	338		124		47		42		61		32		9		14

__________

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

16. Related Party Transactions (All Registrants)

Utility Registrants' expense with Generation

The Utility Registrants incurred expenses from transactions with the Generation affiliate as described in the footnotes to the table below prior to separation on February 1, 2022. Such expenses were primarily recorded as Purchased power from affiliate and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants. Effective February 1, 2022, Generation is no longer considered a related party.


	Six Months Ended June 30,
	2022
ComEd(a)	$	59
PECO(b)	33
BGE(c)	18
PHI	51
Pepco(d)	39
DPL(e)	10
ACE(f)	2

__________

(a)ComEd had an ICC-approved RFP contract with Generation to provide a portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Generation.

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

(c)BGE received a portion of its energy requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.

(d)Pepco received electric supply from Generation under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.

(e)DPL received a portion of its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs.

(f)ACE received electric supply from Generation under contracts executed through ACE's competitive procurement process approved by the NJBPU.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 16 — Related Party Transactions

Service Company Costs for Corporate Support

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

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


	Operating and maintenance from affiliates								Capitalized costs
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022		2023		2022		2023		2022
Exelon
BSC									$	165	$	139	$	340	$	344
PHISCO									25		21		49		40
ComEd
BSC	$	88	$	80	$	171	$	165	78		67		159		152
PECO
BSC	54		47		105		96		30		20		60		56
BGE
BSC	54		51		108		102		22		22		46		60
PHI
BSC	43		46		85		96		35		30		75		76
PHISCO	—		—		—		—		25		21		49		40
Pepco
BSC	28		27		55		56		14		11		28		28
PHISCO	30		29		60		58		10		8		21		16

DPL
BSC	18		17		35		35		10		9		20		23
PHISCO	25		25		49		49		8		7		15		13

ACE
BSC	15		14		29		29		12		10		26		25
PHISCO	22		22		44		43		7		6		13		11

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 16 — Related Party Transactions

Current Receivables from/Payables to affiliates

The following tables present current Receivables from affiliates and current Payables to affiliates:

June 30, 2023


				Receivables from affiliates:
	Payables to affiliates:			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
ComEd					$	—		$	—		$	—		$	—		$	—		$	62		$	—		$	9		$	71
PECO		$	—					—			—			—			—			33			—			3			36
BGE		—			—						—			—			—			30			—			2			32
PHI		—			—			—			—			—			—			7			—			11			18
Pepco		—			—			—						—			—			17			15			—			32
DPL		—			—			—			—						—			11			11			1			23
ACE		—			—			—			—			—						10			11			1			22
Other		3			1			—			—			—			2			—			—						6
Total		$	3		$	1		$	—		$	—		$	—		$	2		$	170		$	37		$	27		$	240

December 31, 2022


				Receivables from affiliates:
	Payables to affiliates:			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
ComEd					$	—		$	—		$	—		$	—		$	—		$	66		$	—		$	8		$	74
PECO		$	—					—			—			—			—			39			—			3			42
BGE		—			—						—			—			—			38			—			1			39
PHI		—			—			—			—			—			—			4			—			10			14
Pepco		—			—			—						—			—			20			13			1			34
DPL		—			2			—			—						—			12			8			—			22
ACE		—			2			—			—			—						14			9			1			26
Other		3			—			—			—			—			1			—			—						4
Total		$	3		$	4		$	—		$	—		$	—		$	1		$	193		$	30		$	24		$	255

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. PECO and PHI Corporate participate in the Exelon intercompany money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.

Long-term debt to financing trusts

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


	June 30, 2023						December 31, 2022
	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

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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 energy transmission and distribution businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.

Exelon has six reportable segments consisting of 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 seven separate operating subsidiary registrants, 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, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders from continuing operations by Registrant for the three and six months ended June 30, 2023 compared to the same period in 2022. For additional information regarding the financial results for the three and six months ended June 30, 2023 and 2022, see the discussions of Results of Operations by Registrant.


	Three Months Ended June 30,				(Unfavorable) Favorable Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Exelon	$	343	$	465	$	(122)	$	1,012	$	946	$	66
ComEd	249		227		22		489		415		74
PECO	97		133		(36)		263		339		(76)
BGE	42		37		5		241		234		7
PHI	103		100		3		258		230		28
Pepco	64		70		(6)		130		116		14
DPL	25		21		4		85		77		8
ACE	18		11		7		51		37		14
Other(a)	(148)		(32)		(116)		(239)		(272)		33

__________

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

The separation of Constellation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, Generation's results of operations are presented as discontinued operations and have been excluded from Exelon's continuing operations for the three and six months ended June 30, 2022 presented in the table above. See Note 1 — Significant Accounting Policies and Note 2 — Discontinued Operations for additional information.

Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Such costs are included in Other in the table above and were $28 million on a pre-tax basis, for the six months ended

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June 30, 2022. There were no such costs included in Exelon's continuing operations for the three months ended June 30, 2022

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net income attributable to common shareholders from continuing operations decreased by $122 million and diluted earnings per average common share from continuing operations decreased to $0.34 in 2023 from $0.47 in 2022 primarily due to:

•Higher interest expense at BGE and Exelon Corporate;

•Unfavorable weather at PECO; and

•Higher depreciation expense at PECO.

The decreases were partially offset by:

•The favorable impacts of rate increases at PECO, BGE, and PHI;

•Higher electric distribution formula rate earnings from higher allowed ROE due to an increase in U.S. treasury rates and impacts of higher rate base at ComEd; and

•Carrying costs related to the CMC regulatory assets at ComEd.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net income attributable to common shareholders from continuing operations increased by $66 million and diluted earnings per average common share from continuing operations increased to $1.02 in 2023 from $0.96 in 2022 primarily due to:

•The favorable impacts of rate increases at PECO, BGE, and PHI;

•Higher electric distribution formula rate earnings from higher allowed ROE due to an increase in U.S. treasury rates and impacts of higher rate base at ComEd;

•Carrying costs related to the CMC regulatory assets at ComEd; and

•Lower BSC costs presented in Exelon’s continuing operations, which were previously allocated to Generation but did not qualify as discontinued operation expenses per the accounting rules.

The increases were partially offset by:

•Unfavorable weather at PECO and PHI;

•Higher interest expense at PECO, BGE, and Exelon Corporate;

•An increase in environmental liabilities at PHI;

•Higher contracting costs due to timing at PECO; and

•Higher depreciation expense at PECO.

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

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The following tables provide a reconciliation between Net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the three and six months ended June 30, 2023 compared to the same period in 2022:


	Three Months Ended June 30,
	2023				2022
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net Income Attributable to Common Shareholders from Continuing Operations	$	343	$	0.34	$	465	$	0.47
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $1)	3		—		—		—
Change in Environmental Liabilities (net of taxes of $1)	11		0.01		—		—

SEC Matter Loss Contingency (net of taxes of $0)	46		0.05		—		—




Separation Costs (net of taxes of $2 and $4, respectively)(a)	5		0.01		10		0.01
Income Tax-Related Adjustments (entire amount represents tax expense)(b)	—		—		(43)		(0.04)
Adjusted (non-GAAP) Operating Earnings	$	408	$	0.41	$	433	$	0.44


	Six Months Ended June 30,
	2023				2022
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net Income Attributable to Common Shareholders from Continuing Operations	$	1,012	$	1.02	$	946	$	0.96
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $1)	2		—		—		—
Change in Environmental Liabilities (net of taxes of $8)	29		0.03		—		—
ERP System Implementation Costs (net of taxes of $0)(c)	—		—		1		—
SEC Matter Loss Contingency (net of taxes of $0)	46		0.05		—		—
Change in FERC Audit Liability (net of taxes of $4)	11		0.01		—		—



Separation Costs (net of taxes of $1 and $11, respectively)(a)	4		—		27		0.03
Income Tax-Related Adjustments (entire amount represents tax expense)(d)	—		—		92		0.09
Adjusted (non-GAAP) Operating Earnings	$	1,104	$	1.11	$	1,065	$	1.08

__________

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2023 and 2022 ranged from 24.0% to 29.0%.

(a)Represents costs related to the separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs, which are recorded in Operating and maintenance expense.

(b)In connection with the separation, Exelon recorded a one-time impact associated with a state tax benefit.

(c)Reflects costs related to a multi-year ERP system implementation, which are recorded in Operating and maintenance expense.

(d)In connection with the separation, Exelon recorded an income tax expense primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit.

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Significant 2023 Transactions and Developments

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 (“the separation”). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purpose of separation and holds Generation. The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation met the criteria for discontinued operations. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation and discontinued operations.

In connection with the separation, Exelon incurred separation costs impacting continuing operations of $7 million and $14 million on a pre-tax basis for the three months ended June 30, 2023 and 2022, respectively, and $5 million and $38 million on a pre-tax basis for the six months ended June 30, 2023 and 2022, respectively, which are recorded in Operating and maintenance expense. Total separation costs impacting continuing operations for the remainder of 2023 are not expected to be material. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The separation costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs.

Distribution Base Rate Case 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 2023. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Completed Distribution Base Rate Case Proceedings


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase		Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois	April 15, 2022	Electric	$	199	$	199	7.85	%	November 17, 2022	January 1, 2023

PECO - Pennsylvania	March 31, 2022	Natural Gas	82		55		N/A		October 27, 2022	January 1, 2023
BGE - Maryland	May 15, 2020 (amended September 11, 2020)	Electric	203		140		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	108		74		9.65	%
Pepco - Maryland	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021
DPL - Maryland	May 19, 2022	Electric	38		29		9.60	%	December 14, 2022	January 1, 2023

Pending Distribution Base Rate Case Proceedings

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Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

ComEd - Illinois

January 17, 2023

Electric

1,545

10.50% to 10.65%

Fourth quarter of 2023

ComEd - Illinois

April 21, 2023

Electric

247

8.91

Fourth quarter of 2023

BGE - Maryland

February 17, 2023

Electric

313

10.40

Fourth quarter of 2023

Natural Gas

289

10.40

Pepco - District of Columbia

April 13, 2023

Electric

191

10.50

Second quarter of 2024

Pepco - Maryland

May 16, 2023

Electric

214

10.50

Second quarter of 2024

DPL - Delaware

December 15, 2022 (amended May 30, 2023)

Electric

10.50

Second quarter of 2024

ACE - New Jersey

February 15, 2023 (amended June 2, 2023)

Electric

10.50

First quarter of 2024

Transmission Formula Rates

For 2023, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.


Registrant	Initial Revenue Requirement Increase		Annual Reconciliation Increase (Decrease)		Total Revenue Requirement Increase		Allowed Return on Rate Base		Allowed ROE
ComEd	$	20	$	63	$	83	8.09	%	11.50	%
PECO	24		23		47		7.41	%	10.35	%
BGE	19		(12)		4		7.34	%	10.50	%
Pepco	37		(5)		32		7.57	%	10.50	%
DPL	32		(3)		29		7.08	%	10.50	%
ACE	41		(12)		29		7.08	%	10.50	%

ComEd's FERC Audit

The Utility Registrants are subject to periodic audits by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit covered the period from January 1, 2017 to present. During the first quarter of 2023, ComEd was provided with information from FERC about several potential findings, including ComEd's methodology regarding the allocation of certain overhead costs to capital under FERC regulations. Based on the preliminary findings and discussions with FERC staff, ComEd determined that a loss was probable and recorded a regulatory liability to reflect its best estimate of that loss as of March 31, 2023.

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Other Key Business Drivers and Management Strategies

The following discussion of other key business drivers 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 in the 2022 Form 10-K, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the 2022 Form 10-K, and Note 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.

Legislative and Regulatory Developments

City of Chicago Franchise Agreement

The current ComEd Franchise Agreement with the City of Chicago (the City) has been in force since 1992. The Franchise Agreement grants rights to use the public right of way to install, maintain, and operate the wires, poles, and other infrastructure required to deliver electricity to residents and businesses across the City. The Franchise Agreement became terminable on one year notice as of December 31, 2020. It now continues in effect indefinitely unless and until either party issues a notice of termination, effective one year later, or it is replaced by mutual agreement with a new franchise agreement between ComEd and the City. If either party terminates and no new agreement is reached between the parties, the parties could continue with ComEd providing electric services within the City with no franchise agreement in place. The City also has an option to terminate and purchase the ComEd system (“municipalize”), which also requires one year notice. Neither party has issued a notice of termination at this time, the City has not exercised its municipalization option, and no new agreement has become effective. Accordingly, the 1992 Franchise Agreement remains in effect at this time. In April 2021, the City invited interested parties to respond to a Request for Information (RFI) regarding the franchise for electricity delivery. Final responses to the RFI were due on July 30, 2021, however, on July 29, 2021, the City chose to extend the final submission deadline to September 30, 2021. ComEd submitted its response to the RFI by the due date. However, the City did not proceed to issue an RFP. Since that time, ComEd and the City continued to negotiate and have arrived at a proposed Chicago Franchise Agreement (CFA) and an Energy and Equity Agreement (EEA). These agreements together are intended to grant ComEd the right to continue providing electric utility services using public ways within the City of Chicago, and to create a new non-profit entity to advance energy and energy-related equity projects. On February 1, 2023, the proposed CFA and EEA were introduced to the City Council. The proposed CFA and EEA remain subject to approval by the City Council and the Exelon Board.

While Exelon and ComEd cannot predict the ultimate outcome of these processes, fundamental changes in the agreements or other adverse actions affecting ComEd’s business in the City would require changes in their business planning models and operations and could have a material adverse impact on Exelon’s and ComEd’s consolidated financial statements. If the City were to disconnect from the ComEd system, ComEd would seek full compensation for the business and its associated property taken by the City, as well as for all damages resulting to ComEd and its system. ComEd would also seek appropriate compensation for stranded costs with FERC.

Infrastructure Investment and Jobs Act

On November 15, 2021, President Biden signed the $1.2 trillion IIJA into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. Federal

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agencies are developing guidelines to implement spending programs under IIJA. The time needed to develop these guidelines will vary with some limited program applications opened as early as the first quarter of 2022. The Registrants are continuing to analyze the legislation and considering possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.

In September 2022, ComEd and BGE applied for the MMG, which establishes and funds construction, improvement, or acquisition of middle mile broadband infrastructure which creates high-speed internet services. The MMG addresses inequitable broadband access by expansion and extension of the middle mile infrastructure in underserved communities. In June 2023, the National Telecommunications and Information Administration (NTIA) announced it selected two of the applications submitted by BGE and ComEd; awarding ComEd and BGE $14.5 million and $15.4 million respectively. The applications selected by NTIA for BGE and ComEd proposed projects designed to enhance electric grid reliability and resiliency while leading and advancing shared local, state, and national goals to increase broadband connectivity, redundancy, affordability, and equity.

In March 2023, Exelon, ComEd and PHI submitted three applications related to the Smart Grid Grants program under section 40107 of IIJA. These applications are focused on replacing existing Advanced Distribution Management Systems (ADMS) in support of distributed energy resources (DERs) and grid-edged technologies, strengthening interoperability and data architecture of systems in support of two-way power flows and accelerating advanced metering deployment in disadvantaged communities. In April 2023, ComEd, PECO BGE and PHI submitted seven applications related to the Grid Resilience Grants program under section 40101(c) of IIJA. These applications are broadly focused on improving grid resilience with an emphasis on disadvantaged communities, relief of capacity constraints and modernizing infrastructure, deployment of DER and microgrid technologies and providing improved resilience through storm hardening projects. Through its applications under section 40107 and 40101(c) of IIJA, the Registrants are requesting nearly $700 million in proposed federal funding. The grant process is expected to be highly competitive, and therefore, the Registrants cannot predict how many of their total applications will be approved as filed, or the precise timing of receiving any funds if they are awarded a grant.

The Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon operates in plus Washington D.C. under a program that will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the use of hydrogen as a clean energy carrier that can deliver or store energy. Applications for the three opportunities under this program were submitted in April 2023. The selection process is expected to be highly competitive, and therefore, the Registrants cannot predict how many of their total applications will be approved as filed or the precise timing of receiving any funds if they are awarded a grant.

PJM Regional Transmission Expansion

On April 6, 2023, PJM received a deactivation notice for Brandon Shores, a 1,282 MW coal generation plant located in BGE service territory. The deactivation was requested for June 1, 2025 and will result in numerous reliability issues across the region. In June 2023, PJM assigned a portion of transmission system upgrades to mitigate these reliability impacts to PECO, BGE and Pepco. In July 2023, PJM Board of Managers approved assigning Exelon transmission system upgrades to mitigate these reliability impacts to PECO, BGE and Pepco. The projected capital expenditures associated with these upgrades are approximately $140 million, $650 million, and $80 million for PECO, BGE and Pepco, respectively, and are expected to be completed by the end of 2028.

Separately, PJM held a competitive transmission proposal window from February 24, 2023 through May 31, 2023 to address reliability issues driven by significant load increases in northern Virginia. PECO, BGE and Pepco submitted four solution proposals, with projected capital expenditures ranging from approximately $322 million to $2.26 billion. PJM is expected to approve the solution in December 2023. The selection process is expected to be highly competitive, and therefore, PECO, BGE, and Pepco cannot predict which, if any, of their solution proposals will be selected by PJM.

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. As of June 30, 2023, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2022. See ITEM 7. MANAGEMENT'S DISCUSSION

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AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2022 Form 10-K for further information.

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Results of Operations by Registrant

Results of Operations — ComEd


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Operating revenues	$	1,901	$	1,425	$	476	$	3,568	$	3,158	$	410
Operating expenses
Purchased power	685		283		(402)		1,172		921		(251)
Operating and maintenance	355		338		(17)		692		689		(3)
Depreciation and amortization	350		328		(22)		688		649		(39)
Taxes other than income taxes	88		90		2		182		185		3
Total operating expenses	1,478		1,039		(439)		2,734		2,444		(290)
Loss on sales of assets	—		(2)		2		—		(2)		2
Operating income	423		384		39		834		712		122
Other income and (deductions)
Interest expense, net	(120)		(104)		(16)		(237)		(204)		(33)
Other, net	17		13		4		34		26		8
Total other income and (deductions)	(103)		(91)		(12)		(203)		(178)		(25)
Income before income taxes	320		293		27		631		534		97
Income taxes	71		66		(5)		142		119		(23)
Net income	$	249	$	227	$	22	$	489	$	415	$	74

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net income increased by $22 million as compared to the same period in 2022, primarily due to increases in electric distribution formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of higher rate base) and carrying costs related to the CMC regulatory assets.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net income increased by $74 million as compared to the same period in 2022, primarily due to increases in electric distribution formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of higher rate base) and carrying costs related to the CMC regulatory assets.

The changes in Operating revenues consisted of the following:


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase		Increase (Decrease)
Distribution	$	63	$	174
Transmission	4		(8)
Energy efficiency	24		39
Other	1		2
	92		207
Regulatory required programs	384		203
Total increase	$	476	$	410

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms implemented pursuant to FEJA.

Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations

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ComEd

in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased for the three and six months ended June 30, 2023 as compared to the same period in 2022, due to higher allowed ROE due to an increase in U.S. Treasury rates, the impact of a higher rate base, and higher fully recoverable costs.

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

Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased for the three and six months ended June 30, 2023 as compared to the same period in 2022, primarily due to increased regulatory asset amortization, which is fully recoverable.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue increased for the three and six months ended June 30, 2023 as compared to the same period in 2022, which primarily reflects mutual assistance revenues associated with storm restoration efforts.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs. ETAC is a retail customer surcharge collected by electric utilities operating in Illinois established by CEJA and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore 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, CMC, 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, CMCs, 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 $402 million and $251 million for the three and six months ended June 30, 2023 compared to the same period in 2022, in Purchased power expense is primarily due to the CMCs from the participating nuclear-powered generating facilities including the deferral of any associated carrying costs. This increase is primarily offset by an increase in Operating revenues as part of regulatory required programs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs.

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ComEd

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


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase (Decrease)		Increase (Decrease)

Labor, other benefits, contracting and materials	$	8	$	25
Storm-related costs	7		8
BSC costs	8		5

Pension and non-pension postretirement benefits expense	(4)		(7)

Other	12		(1)
	31		30
Regulatory required programs(a)	(14)		(27)
Total increase	$	17	$	3

__________

(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.

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


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase		Increase
Depreciation and amortization(a)	$	15	$	28
Regulatory asset amortization(b)	7		11

Total increase	$	22	$	39

__________

(a)Reflects ongoing capital expenditures and higher depreciation rates effective January 2023.

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

Interest expense, net increased by $16 million and $33 million for the three and six months ended June 30, 2023, compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt during the year.

Effective income tax rates were 22.2% and 22.5% for the three months ended June 30, 2023 and 2022, respectively, and 22.5% and 22.3% for the six months ended June 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PECO

Results of Operations — PECO


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Operating revenues	$	828	$	816	$	12	$	1,940	$	1,863	$	77
Operating expenses
Purchased power and fuel	302		283		(19)		786		689		(97)
Operating and maintenance	239		215		(24)		510		463		(47)
Depreciation and amortization	99		93		(6)		197		185		(12)
Taxes other than income taxes	47		48		1		97		95		(2)
Total operating expenses	687		639		(48)		1,590		1,432		(158)

Operating income	141		177		(36)		350		431		(81)
Other income and (deductions)
Interest expense, net	(48)		(43)		(5)		(97)		(84)		(13)
Other, net	6		8		(2)		15		16		(1)
Total other income and (deductions)	(42)		(35)		(7)		(82)		(68)		(14)
Income before income taxes	99		142		(43)		268		363		(95)
Income taxes	2		9		7		5		24		19


Net income	$	97	$	133	$	(36)	$	263	$	339	$	(76)

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net income decreased by $36 million primarily due to unfavorable weather and increase in depreciation and amortization expense, partially offset by an increase in gas distribution rates.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net income decreased by $76 million, primarily due to unfavorable weather and increases in operating expenses, depreciation and amortization expense, and interest expense, partially offset by an increase in gas distribution rates.

The changes in Operating revenues consisted of the following:


	Three Months Ended June 30, 2023						Six Months Ended June 30, 2023
	(Decrease) Increase						(Decrease) Increase
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	(33)	$	(3)	$	(36)	$	(57)	$	(27)	$	(84)
Volume	(3)		(1)		(4)		(10)		1		(9)
Pricing	6		6		12		18		29		47
Transmission	4		—		4		1		—		1
Other	—		—		—		(1)		5		4
	(26)		2		(24)		(49)		8		(41)
Regulatory required programs	38		(2)		36		116		2		118
Total increase	$	12	$	—	$	12	$	67	$	10	$	77

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and six months ended June 30, 2023 compared to the same period in 2022, Operating revenues related to weather decreased by the impact of unfavorable weather conditions in PECO's service territory.

Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in

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PECO

PECO’s service territory for the three and six months ended June 30, 2023 compared to the same period in 2022 and normal weather consisted of the following:


	Three Months Ended June 30,			% Change
PECO Service Territory	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	330	385	426	(14.3)	%	(22.5)	%
Cooling Degree-Days	233	434	386	(46.3)	%	(39.6)	%
	Six Months Ended June 30,			% Change
	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	2,218	2,613	2,843	(15.1)	%	(22.0)	%
Cooling Degree-Days	233	435	387	(46.4)	%	(39.8)	%

Volume. Electric volume, exclusive of the effects of weather, for the three and six months ended June 30, 2023 compared to the same period in 2022, remained relatively consistent. Natural gas volume for the three and six months ended June 30, 2023 compared to the same period in 2022, remained relatively consistent.


Electric Retail Deliveries to Customers (in GWhs)	Three Months Ended June 30,		% Change		Weather - Normal % Change(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change(b)
	2023	2022					2023	2022
Residential	2,694	3,060	(12.0)	%	(0.1)	%	6,052	6,818	(11.2)	%	(1.7)	%
Small commercial & industrial	1,703	1,813	(6.1)	%	(2.9)	%	3,546	3,750	(5.4)	%	(0.5)	%
Large commercial & industrial	3,331	3,416	(2.5)	%	(0.6)	%	6,568	6,748	(2.7)	%	(0.2)	%
Public authorities & electric railroads	144	135	6.7	%	6.4	%	312	317	(1.6)	%	(1.9)	%
Total electric retail deliveries(a)	7,872	8,424	(6.6)	%	(0.8)	%	16,478	17,633	(6.6)	%	(0.9)	%


	At June 30,
Number of Electric Customers	2023	2022
Residential	1,529,499	1,521,728
Small commercial & industrial	155,845	155,484
Large commercial & industrial	3,112	3,114
Public authorities & electric railroads	10,423	10,386
Total	1,698,879	1,690,712

__________

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

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


Natural Gas Deliveries to Customers (in mmcf)	Three Months Ended June 30,		% Change		Weather - Normal % Change(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change(b)
	2023	2022					2023	2022
Residential	4,373	5,206	(16.0)	%	(9.8)	%	21,563	26,043	(17.2)	%	(3.8)	%
Small commercial & industrial	3,743	3,638	2.9	%	6.8	%	12,442	14,184	(12.3)	%	(0.9)	%
Large commercial & industrial	6	4	50.0	%	(4.0)	%	35	14	150.0	%	9.1	%
Transportation	5,190	5,707	(9.1)	%	(7.0)	%	12,204	13,346	(8.6)	%	(6.1)	%
Total natural gas retail deliveries(a)	13,312	14,555	(8.5)	%	(4.6)	%	46,244	53,587	(13.7)	%	(3.5)	%

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PECO


	At June 30,
Number of Natural Gas Customers	2023	2022
Residential	504,723	499,678
Small commercial & industrial	44,793	44,726
Large commercial & industrial	10	10
Transportation	642	659
Total	550,168	545,073

__________

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

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

Pricing for the three and six months ended June 30, 2023 compared to the same period in 2022 increased primarily due to an increase in gas distribution rates charged to customers.

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.

Other revenue primarily includes revenue related to late payment charges. Other revenue for the three and six months ended June 30, 2023 compared to the same period in 2022 remained relatively consistent.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.

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

The increase of $97 million and $19 million for the three and six months ended June 30, 2023 compared to the same period in 2022, in Purchased power and fuel expense is offset in Operating revenues as part of regulatory required programs.

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PECO

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


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting and materials	$	10	$	21
BSC costs	6		8
Storm-related costs	5		1
Pension and non-pension postretirement benefit expense	—		(2)
Credit loss expense	(12)		(2)
Other	2		2
	11		28
Regulatory required programs	13		19
Total increase	$	24	$	47

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


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	7	$	13
Regulatory asset amortization	(1)		(1)

Total increase	$	6	$	12

__________

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

Interest expense, net increased $5 million and $13 million for the three and six months ended June 30, 2023, compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt in 2022.

Effective income tax rates were 2.0% and 6.3% for the three months ended June 30, 2023 and 2022, respectively, and 1.9% and 6.6% for the six months ended June 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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BGE

Results of Operations — BGE


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Operating revenues	$	797	$	786	$	11	$	2,053	$	1,940	$	113
Operating expenses
Purchased power and fuel	272		289		17		764		743		(21)
Operating and maintenance	198		205		7		419		423		4
Depreciation and amortization	158		152		(6)		325		322		(3)
Taxes other than income taxes	76		71		(5)		159		148		(11)
Total operating expenses	704		717		13		1,667		1,636		(31)

Operating income	93		69		24		386		304		82
Other income and (deductions)
Interest expense, net	(44)		(36)		(8)		(88)		(71)		(17)
Other, net	5		5		—		8		11		(3)
Total other income and (deductions)	(39)		(31)		(8)		(80)		(60)		(20)
Income before income taxes	54		38		16		306		244		62
Income taxes	12		1		(11)		65		10		(55)
Net income	$	42	$	37	$	5	$	241	$	234	$	7

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net income increased $5 million primarily due to favorable impacts of the multi-year plans, partially offset by an increase in interest expense. 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 plans.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net Income increased $7 million primarily due to favorable impacts of the multi-year plans, partially offset by an increase in interest expense. 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 plans.

The changes in Operating revenues consisted of the following:


	Three Months Ended June 30, 2023						Six Months Ended June 30, 2023
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Distribution	$	16	$	6	$	22	$	42	$	29	$	71
Transmission	12		—		12		30		—		30
Other	(1)		1		—		(1)		2		1
	27		7		34		71		31		102
Regulatory required programs	16		(39)		(23)		49		(38)		11
Total increase (decrease)	$	43	$	(32)	$	11	$	120	$	(7)	$	113

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 monthly rate adjustment that provides for fixed distribution revenue per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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BGE


	At June 30,
Number of Electric Customers	2023	2022
Residential	1,206,763	1,200,397
Small commercial & industrial	115,594	115,769
Large commercial & industrial	12,975	12,721
Public authorities & electric railroads	265	267
Total	1,335,597	1,329,154


	At June 30,
Number of Natural Gas Customers	2023	2022
Residential	655,181	653,409
Small commercial & industrial	38,077	38,227
Large commercial & industrial	6,275	6,211

Total	699,533	697,847

Distribution Revenue increased for the three and six months ended June 30, 2023, compared to the same period in 2022, due to favorable impacts of the multi-year plans.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and six months ended June 30, 2023, compared to the same period in 2022, primarily due to increases in underlying costs and capital investments.

Other Revenue includes revenue related to late payment, charges, mutual assistance, off-system sales, and service application fees. Other Revenue remained relatively the same for the three and six months ended June 30, 2023 compared to the same period in 2022.

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 decrease of $17 million and increase of $21 million for the three and six months ended June 30, 2023 compared to the same period in 2022, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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BGE

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


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting, and materials	$	4	$	12
Storm-related costs	5		—
Pension and non-pension postretirement benefits expense	1		3
BSC costs	3		6
Credit loss expense	(15)		(15)

Other	(5)		(11)
	(7)		(5)
Regulatory required programs	—		1

Total decrease	$	(7)	$	(4)

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


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	6	$	13
Regulatory required programs	1		(9)
Regulatory asset amortization	(1)		(1)

Total increase	$	6	$	3

__________

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

Interest expense, net increased by $8 million and $17 million for the three and six months ended June 30, 2023, respectively compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt in 2023 and 2022.

Taxes other than income taxes increased by $5 million and $11 million for the three and six months ended June 30, 2023, respectively, compared to the same period in 2022, primarily due to increased property taxes.

Effective income tax rates were 22.2% and 2.6% for the three months ended June 30, 2023 and 2022 respectively, and 21.2% and 4.1% for the six months ended June 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PHI

Results of Operations — PHI

PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services, and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three and six months ended June 30, 2023 compared to the same period in 2022. See the Results of Operations for Pepco, DPL, and ACE for additional information.


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
PHI	$	103	$	100	$	3	$	258	$	230	$	28
Pepco	64		70		(6)		130		116		14
DPL	25		21		4		85		77		8
ACE	18		11		7		51		37		14
Other(a)	(4)		(2)		(2)		(8)		—		(8)

__________

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

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net Income increased by $3 million primarily due to favorable impacts of the Pepco Maryland and DPL Maryland multi-year plans, higher distribution rates at DPL Delaware, higher transmission rates at Pepco and ACE, and a decrease in various operating expenses, partially offset by an increase in environmental liabilities at Pepco.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net Income increased by $28 million primarily due to favorable impacts of the Pepco Maryland and DPL Maryland multi-year plans, customer growth in the District of Columbia and Maryland, timing of decoupling revenues in the District of Columbia, higher distribution rates at DPL Delaware, and higher transmission rates at Pepco and ACE, partially offset by an increase in environmental liabilities at Pepco, and unfavorable weather conditions at DPL Delaware electric and natural gas service territories.

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Pepco

Results of Operations — Pepco


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Operating revenues	$	642	$	581	$	61	$	1,351	$	1,195	$	156


Operating expenses
Purchased power	204		162		(42)		462		375		(87)
Operating and maintenance	140		128		(12)		290		260		(30)
Depreciation and amortization	109		105		(4)		216		213		(3)
Taxes other than income taxes	88		92		4		183		186		3
Total operating expenses	541		487		(54)		1,151		1,034		(117)

Operating income	101		94		7		200		161		39
Other income and (deductions)
Interest expense, net	(43)		(38)		(5)		(81)		(74)		(7)
Other, net	16		13		3		33		26		7
Total other income and (deductions)	(27)		(25)		(2)		(48)		(48)		—
Income before income taxes	74		69		5		152		113		39
Income taxes	10		(1)		(11)		22		(3)		(25)
Net income	$	64	$	70	$	(6)	$	130	$	116	$	14

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net Income decreased by $6 million primarily due to an increase in environmental liabilities, partially offset by higher transmission rates and favorable impacts of the Pepco Maryland multi-year plan.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net Income increased by $14 million primarily due to favorable impacts of the Maryland multi-year plan, timing of decoupling revenues in the District of Columbia, higher transmission rates and customer growth in the District of Columbia and Maryland, partially offset by an increase in environmental liabilities.

The changes in Operating revenues consisted of the following:


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase		Increase
Distribution	$	13	$	53
Transmission	10		27
Other	1		1
	24		81
Regulatory required programs	37		75
Total increase	$	61	$	156

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 BSA that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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Pepco


	At June 30,
Number of Electric Customers	2023	2022
Residential	860,014	850,569
Small commercial & industrial	54,016	54,349
Large commercial & industrial	22,904	22,771
Public authorities & electric railroads	204	194
Total	937,138	927,883

Distribution Revenue increased for the three months ended June 30, 2023 compared to the same period in 2022 primarily due to higher rates due to the expiration of customer offsets and favorable impacts of the Maryland multi-year plan. Distribution revenue increased for the six months ended June 30, 2023 compared to the same period in 2022 primarily due to favorable impacts of the Maryland multi-year plan, higher rates due to the expiration of customer offsets, timing of decoupling revenues in the District of Columbia, and customer growth in the District of Columbia and Maryland.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for both the three and six months ended June 30, 2023, compared to the same period in 2022, primarily due to increases in capital investment and underlying costs.

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, Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.

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

The increase of $42 million and $87 million for the three and six months ended June 30, 2023 compared to the same period in 2022, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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Pepco

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


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase (Decrease)		Increase (Decrease)
Pension and non-pension postretirement benefits expense	$	3	$	6
BSC and PHISCO costs	2		1
Storm-related costs	—		(5)
Credit Loss expense	(1)		(5)
Labor, other benefits, contracting and materials(a)	(2)		22

Other	9		5
	11		24

Regulatory required programs	1		6
Total increase	$	12	$	30

__________

(a)Primarily reflects an increase in environmental liabilities for the six months ended June 30, 2023.

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


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	4	$	7
Regulatory asset amortization	3		7
Regulatory required programs	(3)		(11)
Total increase	$	4	$	3

__________

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

Interest expense, net increased by $5 million and $7 million for the three and six months ended June 30, 2023 compared to the same period in 2022, respectively, primarily due to the issuance of debt in 2023.

Other, net increased by $3 million and $7 million for the three and six months ended June 30, 2023 compared to the same period in 2022, respectively, primarily due to higher AFUDC equity.

Effective income tax rates were 13.5% and (1.4)% for the three months ended June 30, 2023 and 2022, respectively, and 14.5% and (2.7)% for the six months ended June 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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DPL

Results of Operations — DPL


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Operating revenues	$	349	$	332	$	17	$	823	$	763	$	60
Operating expenses
Purchased power and fuel	139		135		(4)		360		324		(36)
Operating and maintenance	88		88		—		175		181		6
Depreciation and amortization	60		56		(4)		121		113		(8)
Taxes other than income taxes	18		17		(1)		37		35		(2)
Total operating expenses	305		296		(9)		693		653		(40)

Operating income	44		36		8		130		110		20
Other income and (deductions)
Interest expense, net	(18)		(17)		(1)		(36)		(33)		(3)
Other, net	4		4		—		8		6		2
Total other income and (deductions)	(14)		(13)		(1)		(28)		(27)		(1)
Income before income taxes	30		23		7		102		83		19
Income taxes	5		2		(3)		17		6		(11)
Net income	$	25	$	21	$	4	$	85	$	77	$	8

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net income increased $4 million primarily due to favorable impacts of the Maryland multi-year plan, and higher Delaware electric and natural gas distribution rates, partially offset by unfavorable weather conditions at Delaware electric and natural gas service territories.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net income increased $8 million primarily due to favorable impacts of the Maryland multi-year plan, and higher Delaware electric and natural gas distribution rates, partially offset by unfavorable weather conditions at Delaware electric and natural gas service territories.

The changes in Operating revenues consisted of the following:


	Three Months Ended June 30, 2023						Six Months Ended June 30, 2023
	(Decrease) Increase						(Decrease) Increase
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	(5)	$	(1)	$	(6)	$	(10)	$	(5)	$	(15)
Volume	—		—		—		(2)		(2)		(4)
Distribution	8		1		9		19		6		25
Transmission	7		—		7		13		—		13
Other	1		(1)		—		2		—		2
	11		(1)		10		22		(1)		21
Regulatory required programs	14		(7)		7		31		8		39
Total increase (decrease)	$	25	$	(8)	$	17	$	53	$	7	$	60

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 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

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weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and six months ended June 30, 2023 compared to the same period in 2022, Operating revenues related to weather decreased due to unfavorable weather conditions in Delaware electric and natural gas service territories.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in the Delaware electric service territory and a 30-year period in the Delaware natural gas service territory. The changes in heating and cooling degree days in the Delaware service territory for the three and six months ended June 30, 2023 compared to same period in 2022 and normal weather consisted of the following:


	Three Months Ended June 30,			% Change
Delaware Electric Service Territory	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	318	441	468	(27.9)	%	(32.1)	%
Cooling Degree-Days	253	328	336	(22.9)	%	(24.7)	%

	Six Months Ended June 30,			% Change
Delaware Electric Service Territory	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	2,269	2,796	2,957	(18.8)	%	(23.3)	%
Cooling Degree-Days	253	331	337	(23.6)	%	(24.9)	%


	Three Months Ended June 30,			% Change
Delaware Natural Gas Service Territory	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	318	441	487	(27.9)	%	(34.7)	%

	Six Months Ended June 30,			% Change
Delaware Natural Gas Service Territory	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	2,269	2,796	2,984	(18.8)	%	(24.0)	%

Volume, exclusive of the effects of weather, remained consistent for the three months ended June 30, 2023 compared to the same period in 2022 and decreased for the six months ended June 30, 2023 compared to the same period in 2022 primarily due to customer usage, partially offset by customer growth.


Electric Retail Deliveries to Delaware Customers (in GWhs)	Three Months Ended June 30,		% Change		Weather - Normal % Change(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change(b)
	2023	2022					2023	2022
Residential	610	675	(9.6)	%	(0.1)	%	1,407	1,570	(10.4)	%	(0.7)	%
Small commercial & industrial	349	337	3.6	%	7.1	%	676	706	(4.2)	%	(0.5)	%
Large commercial & industrial	780	773	0.9	%	2.6	%	1,500	1,538	(2.5)	%	(1.0)	%
Public authorities & electric railroads	8	8	—	%	(0.5)	%	17	17	—	%	(3.7)	%
Total electric retail deliveries(a)	1,747	1,793	(2.6)	%	2.4	%	3,600	3,831	(6.0)	%	(0.8)	%


	At June 30,
Number of Total Electric Customers (Maryland and Delaware)	2023	2022
Residential	483,760	479,728
Small commercial & industrial	63,913	63,574
Large commercial & industrial	1,234	1,222
Public authorities & electric railroads	594	598
Total	549,501	545,122

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DPL

__________

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

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


Natural Gas Retail Deliveries to Delaware Customers (in mmcf)	Three Months Ended June 30,		% Change		Weather - Normal % Change(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change(b)
	2023	2022					2023	2022
Residential	794	983	(19.2)	%	(2.1)	%	4,368	5,436	(19.6)	%	(5.8)	%
Small commercial & industrial	497	570	(12.8)	%	2.3	%	2,142	2,550	(16.0)	%	(0.8)	%
Large commercial & industrial	371	402	(7.7)	%	(7.8)	%	787	863	(8.8)	%	(8.7)	%
Transportation	1,328	1,444	(8.0)	%	(4.8)	%	3,231	3,650	(11.5)	%	(6.1)	%
Total natural gas deliveries(a)	2,990	3,399	(12.0)	%	(3.1)	%	10,528	12,499	(15.8)	%	(5.0)	%


	At June 30,
Number of Delaware Natural Gas Customers	2023	2022
Residential	129,538	128,715
Small commercial & industrial	10,060	10,068
Large commercial & industrial	16	16
Transportation	163	157
Total	139,777	138,956

__________

(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 both the three and six months ended June 30, 2023 compared to the same period in 2022 primarily due to favorable impacts of the Maryland multi-year plan that became effective in January 2023, higher natural gas distribution rates effective in August 2022, and higher electric DSIC rates in Delaware that became effective in January 2023.

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. During the three and six months ended June 30, 2023 compared to the same period in 2022, transmission revenue increased primarily due to increases in underlying costs.

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, 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. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas 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 either acts as the billing agent or the competitive supplier separately bills its own customers, 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.

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

The increase of $4 million and $36 million for the three and six months ended June 30, 2023, compared to the same period in 2022, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	(Decrease) Increase		(Decrease) Increase
Labor, other benefits, contracting and materials	$	(2)	$	(5)
Credit loss expense	(2)		(2)
BSC and PHISCO costs	—		(1)
Pension and non-pension postretirement benefits expense	1		3
Storm-related costs	2		(1)
Other	2		(1)
	1		(7)
Regulatory required programs	(1)		1
Total decrease	$	—	$	(6)

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


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	5	$	12
Regulatory required programs	(1)		(4)

Total increase	$	4	$	8

__________

(a)For the three months ended June 30, 2023, reflects ongoing capital expenditures and higher transmission depreciation rates effective September 2022. For the six months ended June 30, 2023, reflects ongoing capital expenditures, higher distribution depreciation rates in Maryland effective March 2022, and higher transmission depreciation rates effective September 2022.

Effective income tax rates were 16.7% and 8.7% for the three months ended June 30, 2023 and 2022, respectively, and 16.7% and 7.2% for the six months ended June 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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Results of Operations — ACE


	Three Months Ended June 30,				Favorable (Unfavorable) Variance		Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Operating revenues	$	317	$	309	$	8	$	670	$	658	$	12


Operating expenses
Purchased power	124		123		(1)		273		301		28
Operating and maintenance	85		86		1		165		170		5
Depreciation and amortization	68		72		4		135		118		(17)
Taxes other than income taxes	3		2		(1)		4		4		—
Total operating expenses	280		283		3		577		593		16

Operating income	37		26		11		93		65		28
Other income and (deductions)
Interest expense, net	(17)		(17)		—		(34)		(32)		(2)
Other, net	4		2		2		9		5		4
Total other income and (deductions)	(13)		(15)		2		(25)		(27)		2
Income before income taxes	24		11		13		68		38		30
Income taxes	6		—		(6)		17		1		(16)
Net income	$	18	$	11	$	7	$	51	$	37	$	14

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net income increased by $7 million primarily due to higher transmission rates and decreases in various operating expenses.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net income increased by $14 million primarily due to higher transmission rates and decreases in various operating expenses.

The changes in Operating revenues consisted of the following:


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase (Decrease)		Increase (Decrease)
Distribution	$	5	$	12
Transmission	13		25

	18		37
Regulatory required programs	(10)		(25)
Total increase	$	8	$	12

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not impacted by abnormal weather or usage per customer as a result of the CIP which became effective, prospectively, in the third quarter of 2021. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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	At June 30,
Number of Electric Customers	2023	2022
Residential	503,918	501,494
Small commercial & industrial	62,307	62,291
Large commercial & industrial	3,007	3,085
Public authorities & electric railroads	727	726
Total	569,959	567,596

Distribution Revenue increased for both the three and six months ended June 30, 2023 compared to the same period in 2022 due to higher distribution rates primarily due to the expiration of customer credits related to the TCJA tax benefits.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for both the three and six months ended June 30, 2023 compared to the same period in 2022, primarily due to increases in underlying costs and capital investment.

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 Bond Charge, 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, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

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

The increase of $1 million and decrease of $28 million for the three and six months ended June 30, 2023 compared to the same period in 2022, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	(Decrease) Increase		(Decrease) Increase
Storm-related costs	$	(1)	$	(2)
Labor and contracting	—		(3)
BSC and PHISCO costs	1		1

Other	—		1
	—		(3)

Regulatory required programs(a)	(1)		(2)
Total decrease	$	(1)	$	(5)

__________

(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge.

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


	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	Increase (Decrease)		Increase
Depreciation and amortization(a)	$	6	$	13

Regulatory required programs(b)	(10)		4
Total (decrease) increase	$	(4)	$	17

__________

(a)Reflects ongoing capital expenditures and higher transmission depreciation rates effective September 2022.

(b)Regulatory required programs increased primarily due to the regulatory asset amortization of the PPA termination obligation which is fully offset in Operating revenues.

Effective income tax rates were 25.0% and 0.0% for the three months ended June 30, 2023 and 2022, respectively, and 25.0% and 2.6% for the six months ended June 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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Liquidity and Capital Resources (All Registrants)

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

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. 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. 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 $4.0 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 and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

Cash flows related to Generation have not been presented as discontinued operations and are included in the Consolidated Statements of Cash Flows for only 2022. The Exelon Consolidated Statement of Cash Flows for the six months ended June 30, 2022 includes one month of cash flows from Generation.

Cash Flows from Operating Activities

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. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period that began in June 2022, and all of its costs of doing so will be recovered through a rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset.

See Note 3 — Regulatory Matters of the 2022 Form 10-K and Notes 3 — Regulatory Matters and 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.

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The following table provides a summary of the change in cash flows from operating activities for the six months ended June 30, 2023 and 2022 by Registrant:


(Decrease) increase in cash flows from operating activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income (loss)	$	(51)	$	74	$	(76)	$	7	$	28	$	14	$	8	$	14
Adjustments to reconcile net income to cash:
Non-cash operating activities	(824)		(219)		(20)		(87)		2		8		(3)		1
Option premiums (paid), net	39		—		—		—		—		—		—		—
Collateral (paid) received, net	(1,876)		(35)		—		(212)		(594)		(111)		(301)		(182)
Income taxes	74		35		7		35		8		23		5		(12)
Pension and non-pension postretirement benefit contributions	500		154		12		48		59		(1)		1		7
Regulatory assets and liabilities, net	(140)		(192)		38		(47)		79		30		36		(1)
Changes in working capital and other assets and liabilities	799		(101)		172		191		156		102		52		(7)
(Decrease) increase in cash flows from operating activities	$	(1,479)	$	(284)	$	133	$	(65)	$	(262)	$	65	$	(202)	$	(180)

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. See above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for the six months ended June 30, 2023 and 2022 were as follows:

•See Note 15 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.

•Changes in collateral depended upon whether Generation was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties decreased due to decreasing energy prices. See Note 9 — Derivative Financial Instruments for additional information.

•See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.

•Changes in Pension and non-pension postretirement benefit contributions relate to Exelon's funding strategy and incremental contributions made in 2022 in connection with the separation. See Note 14 — Retirement Benefits of the 2022 Form 10-K for additional information.

•Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $192 million and $115 million for the six months ended June 30, 2023 and 2022, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $66 million, $32 million, $12 million, and $8 million for the six months ended June 30, 2023 and $53 million, $33 million, $13 million, and $4 million for the six months ended June 30, 2022, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the six months ended June 30, 2023 and

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2022. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

•Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $476 million and for Generation total $323 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement which was entered into in April 2020. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the six months ended June 30, 2023, the established pricing resulted in ComEd owing payments to nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts payable and accrued expense.

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the six months ended June 30, 2023 and 2022 by Registrant:


Decrease in cash flows from investing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	(178)	$	(54)	$	(49)	$	(78)	$	(246)	$	(81)	$	(64)	$	(96)

Investment in NDT fund sales, net	28		—		—		—		—		—		—		—
Collection of DPP	(169)		—		—		—		—		—		—		—
Proceeds from sales of assets and businesses	(16)		—		—		—		—		—		—		—
Changes in intercompany money pool	—		—		(225)		—		—		—		(29)		—

Other investing activities	6		(12)		(5)		(3)		5		6		(2)		—
Decrease in cash flows from investing activities	$	(329)	$	(66)	$	(279)	$	(81)	$	(241)	$	(75)	$	(95)	$	(96)

Significant investing cash flow impacts for the Registrants for six months ended June 30, 2023 and 2022 were as follows:

•Changes in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation.

•Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in April 2020.

•Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the six months ended June 30, 2023 and 2022 by Registrant:

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Increase (decrease) in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	(1,553)	$	120	$	(449)	$	(278)	$	48	$	(167)	$	34	$	181
Long-term debt, net	547		225		525		(100)		(50)		50		—		(100)
Changes in intercompany money pool	—		—		—		—		(9)		(21)		—		50

Dividends paid on common stock	(54)		(85)		(2)		(8)		—		185		(4)		2

Distributions to member	—		—		—		—		183		—		—		—
Contributions from parent/member	—		37		103		51		(299)		(144)		(45)		(110)
Transfer of cash, restricted cash, and cash equivalents to Constellation	2,594		—		—		—		—		—		—		—
Other financing activities	2		(1)		4		—		(13)		(13)		—		1
Increase (decrease) in cash flows from financing activities	$	1,536	$	296	$	181	$	(335)	$	(140)	$	(110)	$	(15)	$	24

Significant financing cash flow impacts for the Registrants for the six months ended June 30, 2023 and 2022 were as follows:

•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants.

•Long-term debt, net, varies due to debt issuances and redemptions each year. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the debt redemptions table below for additional information.

•Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.

•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 18 — Commitments and Contingencies of the 2022 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.

•Refer to Note 2 — Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation.

Debt

See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

During the six months ended June 30, 2023, the following long-term debt was retired and/or redeemed:

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Company

Type

Interest Rate

Maturity

Amount

Exelon

SMBC Term Loan Agreement

SOFR plus 0.65%

July 21, 2023

300

Exelon

US Bank Term Loan Agreement

SOFR plus 0.65%

July 21, 2023

300

Exelon

PNC Term Loan Agreement

SOFR plus 0.65%

July 24, 2023

250

Exelon

Long-Term Software License Agreement

3.70

August 9, 2025

Exelon

Long-Term Software License Agreement

3.95

May 1, 2024

Exelon

Long-Term Software License Agreement

3.70

August 9, 2025

PECO

Loan Agreement

2.00

June 20, 2023

BGE

Notes

3.35

July 1, 2023

300

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the six months ended June 30, 2023 and for the second quarter of 2023 were as follows:

Period

Declaration Date

Shareholder of Record Date

Dividend Payable Date

Cash per Share(a)

First Quarter 2023

February 14, 2023

February 27, 2023

March 10, 2023

0.3600

Second Quarter 2023

April 25, 2023

May 15, 2023

June 9, 2023

0.3600

Third Quarter 2023

July 25, 2023

August 15, 2023

September 8, 2023

0.3600

__________

(a)Exelon's Board of Directors approved an updated dividend policy for 2023. The 2023 quarterly dividend will be $0.36 per share.

Credit Matters and Cash Requirements

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 $4.0 billion in aggregate total commitments of which $3.7 billion was available to support additional commercial paper as of June 30, 2023, and of which no financial institution has more than 6% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the six months ended June 30, 2023 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. 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 2022 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flows from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements.

On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”) with certain sales agents and forward sellers and certain forward purchasers establishing an ATM equity distribution program under which it may offer and sell shares of its common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of common stock under the Equity Distribution Agreement and may at any time suspend or terminate offers and sales under the Equity Distribution Agreement. As of June 30, 2023, Exelon has not issued any shares of common stock under the ATM program and has not entered into any forward sale agreements.

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at June 30, 2023 and available credit facility capacity prior to any incremental collateral at June 30, 2023:

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	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	1	$	—	$	698
PECO	1		21		600
BGE	3		37		598

Pepco	4		—		300
DPL	4		9		300
ACE	2		—		263

__________

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

Capital Expenditure Spending

As of June 30, 2023, the most recent estimates of capital expenditures for plant additions and improvements for 2023 are as follows:


(In millions)	Transmission	Distribution	Gas	Total(a)
Exelon	N/A	N/A	N/A	$	7,175
ComEd	425	2,125	N/A	2,550
PECO	100	975	325	1,400
BGE	325	525	475	1,325
PHI	550	1,225	125	1,900
Pepco	250	675	N/A	900
DPL	175	275	125	575
ACE	125	300	N/A	425

__________

(a)Numbers rounded to the nearest $25M and may not sum due to rounding.

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Retirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $20 million in 2023. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery).

To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns,

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annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.

See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2022 Form 10-K for additional information on pension and OPEB contributions.

Credit Facilities

Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its 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 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.

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 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for the Registrants did not change for the six months ended June 30, 2023. On July 26, 2023, S&P raised ComEd's long-term issuer credit rating from 'BBB+' to a 'A-'. S&P also affirmed the current 'A' rating on ComEd's senior secured debt and 'A-2' short-term rating, which influences long and short-term borrowing cost.

Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of June 30, 2023, are presented in the following table:

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	During the Six Months Ended June 30, 2023				At June 30, 2023
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	510	$	—	$	52
PECO	225		(238)		225
BSC	—		(327)		(270)
PHI Corporate	—		(52)		(52)
PCI	45		—		45


	During the Six Months Ended June 30, 2023				At June 30, 2023
PHI Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		(Borrowed) Contributed
Pepco	$	—	$	(55)	$	(52)
DPL	111		—		102
ACE	—		(68)		(50)

Shelf Registration Statements

Exelon and the Utility Registrants have a currently effective combined shelf registration statement, unlimited in amount, that will expire in August 2025. 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:

At June 30, 2023

Short-term Financing Authority

Remaining Long-term Financing Authority

Commission

Expiration Date

Amount

Commission

Expiration Date

Amount

ComEd(a)

FERC

December 31, 2023

2,500

ICC

January 1, 2025

368

PECO

FERC

December 31, 2023

1,500

PAPUC

December 31, 2024

550

BGE(b)

FERC

December 31, 2023

700

MDPSC

N/A

1,100

Pepco(c)

FERC

December 31, 2023

500

MDPSC / DCPSC

December 31, 2025

1,150

DPL(c)

FERC

December 31, 2023

500

MDPSC / DEPSC

December 31, 2025

1,075

ACE(d)

NJBPU

December 31, 2023

350

NJBPU

December 31, 2024

625

__________

(a)On June 29, 2023, ComEd filed an application for $2 billion in new money long-term debt financing authority from the ICC and expects approval by December 31, 2023.

(b)On December 21, 2022, BGE received approval from the MDPSC for $1.8 billion in new long-term financing authority with an effective date of January 4, 2023.

(c)The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DCPSC and DEPSC have an expiration date of December 31, 2025.

(d)On July 14, 2023, ACE filed an application with the NJBPU for renewal of their short-term financing authority through January 1, 2026. ACE expects approval of their application by December 31, 2023.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

The Registrants hold commodity and financial instruments that are exposed to the following market risks:

•Commodity price risk, which is discussed further below.

•Counterparty credit risk associated with non-performance by counterparties on executed derivative instruments and participation in all, or some of the established, wholesale spot energy markets that are administered by PJM. The credit policies of PJM may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of counterparty credit risk related to derivative instruments.

•Equity price and interest rate risk associated with Exelon’s pension and OPEB plan trusts. See Note 8 — Retirement Benefits of the 2022 Form 10-K for additional information.

•Interest rate risk associated with changes in interest rates for the Registrants’ outstanding long-term debt. This risk is significantly reduced as substantially all of the Registrants’ outstanding debt has fixed interest rates. There is inherent interest rate risk related to refinancing maturing debt by issuing new long-term debt. The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. In addition, Exelon may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges, or to lock in rate levels on borrowings, which are typically designated as economic hedges. See Note 9 – Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

•Electric operating revenues risk associated with ComEd's distribution formula rate. ComEd's ROE for its electric distribution service through 2023 is directly correlated to yields on U.S. Treasury bonds. Exelon Corporate may utilize interest rate derivatives to mitigate volatility and manage risk to Exelon, which are typically accounted for as economic hedges. See Note 9 – Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

The Registrants operate primarily under cost-based rate regulation limiting exposure to the effects of market risk. Hedging programs are utilized to reduce exposure to energy and natural gas price volatility and have no direct earnings impacts as the costs are fully recovered through regulatory-approved recovery mechanisms.

Exelon manages these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. Risk management issues are reported to Exelon’s Executive Committee, the Risk Management Committees of each Utility Registrant, and the Audit and Risk Committee of Exelon’s Board of Directors.

Commodity Price Risk

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 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 and natural gas.

ComEd entered into 20-year floating-to-fixed renewable energy swap contracts beginning in June 2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. PECO, BGE, Pepco, DPL, and ACE have contracts to procure electric supply that are executed through a competitive procurement process. PECO, BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.

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PECO, BGE, and DPL also have executed derivative natural gas contracts, which qualify for NPNS, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their financial statements.

For additional information on these contracts, see Note 9 — Derivative Financial Instruments and Note 11 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements.

The following table presents the maturity and source of fair value for Exelon’s and ComEd’s mark-to-market commodity contract net liabilities. These net liabilities are associated with ComEd’s floating-to-fixed energy swap contracts with unaffiliated suppliers. The table provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Exelon's and ComEd's total mark-to-market net liabilities. Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract net liabilities giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 11 — 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.


	Maturities Within												Total Fair Value
Commodity derivative contracts(a):	2023		2024		2025		2026		2027		2028 and Beyond		Total Fair Value
Prices based on model or other valuation methods (Level 3)	$	(13)	$	(20)	$	(18)	$	(18)	$	(17)	$	(47)	$	(133)

_________

(a)Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

ITEM 4. CONTROLS AND PROCEDURES

During the second quarter of 2023, 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 that Registrant's management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of June 30, 2023, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There were no changes in internal control over financial reporting during the second quarter of 2023 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 the 2022 Form 10-K, (b) Notes 3 — Regulatory Matters and 18 — Commitments and Contingencies of the 2022 Form 10-K, and (c) Notes 3 — Regulatory Matters and 12 — 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.

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ITEM 1A. RISK FACTORS

Risks Related to All Registrants

At June 30, 2023, the Registrants' risk factors were consistent with the risk factors described in the 2022 Form 10-K in ITEM 1A. RISK FACTORS.

ITEM 5. OTHER INFORMATION

All Registrants

None.

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.

(4) Instruments Defining the Rights of Securities Holders, Including Indentures

PECO Energy Company

Exhibit No.

Description

Location

4-1

Supplemental Indenture to PECO Energy Company’s First and Refunding Mortgage dated as of June 1, 2023

File No. 001-16844, Form 8-K dated June 23, 2023, Exhibit 4.1

Baltimore Gas and Electric Company

Exhibit No.

Description

4-2

Form of 5.400% Note due 2053 issued May 10, 2023 by Baltimore Gas and Electric Company

File No. 001-01910, Form 8-K dated May 10, 2023, Exhibit 4.2

Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2023 filed by the following officers for the following companies:

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Exelon Corporation
Exhibit No.			Description
31-1			Filed by Calvin G. Butler, Jr. for Exelon Corporation

31-2			Filed by Jeanne M. Jones for Exelon Corporation

Commonwealth Edison Company
Exhibit No.			Description
31-3			Filed by Gil C. Quiniones for Commonwealth Edison Company

31-4			Filed by Elisabeth J. Graham for Commonwealth Edison Company

PECO Energy Company
Exhibit No.			Description
31-5			Filed by Michael A. Innocenzo for PECO Energy Company

31-6			Filed by Marissa Humphrey for PECO Energy Company

Baltimore Gas and Electric Company
Exhibit No.			Description
31-7			Filed by Carim V. Khouzami for Baltimore Gas and Electric Company

31-8			Filed by David M. Vahos for Baltimore Gas and Electric Company

Pepco Holdings LLC
Exhibit No.			Description
31-9			Filed by J. Tyler Anthony for Pepco Holdings LLC

31-10			Filed by Phillip S. Barnett for Pepco Holdings LLC

Potomac Electric Power Company
Exhibit No.			Description
31-11			Filed by J. Tyler Anthony for Potomac Electric Power Company

31-12			Filed by Phillip S. Barnett for Potomac Electric Power Company

Delmarva Power & Light Company
Exhibit No.			Description
31-13			Filed by J. Tyler Anthony for Delmarva Power & Light Company

31-14			Filed by Phillip S. Barnett for Delmarva Power & Light Company

Atlantic City Electric Company
Exhibit No.			Description
31-15			Filed by J. Tyler Anthony for Atlantic City Electric Company

31-16			Filed by Phillip S. Barnett for Atlantic City Electric Company

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes-Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2023 filed by the following officers for the following companies:

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Exelon Corporation
Exhibit No.			Description
32-1			Filed by Calvin G. Butler, Jr. for Exelon Corporation

32-2			Filed by Jeanne M. Jones for Exelon Corporation

Commonwealth Edison Company
Exhibit No.			Description
32-3			Filed by Gil C. Quiniones for Commonwealth Edison Company

32-4			Filed by Elisabeth J. Graham for Commonwealth Edison Company

PECO Energy Company
Exhibit No.			Description
32-5			Filed by Michael A. Innocenzo for PECO Energy Company

32-6			Filed by Marissa Humphrey for PECO Energy Company

Baltimore Gas and Electric Company
Exhibit No.			Description
32-7			Filed by Carim V. Khouzami for Baltimore Gas and Electric Company

32-8			Filed by David M. Vahos for Baltimore Gas and Electric Company

Pepco Holdings LLC
Exhibit No.			Description
32-9			Filed by J. Tyler Anthony for Pepco Holdings LLC

32-10			Filed by Phillip S. Barnett for Pepco Holdings LLC

Potomac Electric Power Company
Exhibit No.			Description
32-11			Filed by J. Tyler Anthony for Potomac Electric Power Company

32-12			Filed by Phillip S. Barnett for Potomac Electric Power Company

Delmarva Power & Light Company
Exhibit No.			Description
32-13			Filed by J. Tyler Anthony for Delmarva Power & Light Company

32-14			Filed by Phillip S. Barnett for Delmarva Power & Light Company

Atlantic City Electric Company
Exhibit No.			Description
32-15			Filed by J. Tyler Anthony for Atlantic City Electric Company

32-16			Filed by Phillip S. Barnett for Atlantic City Electric Company

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)

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SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON CORPORATION


/s/ CALVIN G. BUTLER, JR.						/s/ JEANNE M. JONES
Calvin G. Butler, Jr.						Jeanne M. Jones
President, Chief Executive Officer (Principal Executive Officer) and Director						Executive Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ ROBERT A. KLECZYNSKI
Robert A. Kleczynski
Senior Vice President, Corporate Controller and Tax (Principal Accounting Officer)

August 2, 2023

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

COMMONWEALTH EDISON COMPANY


/s/ GIL C. QUINIONES						/s/ ELISABETH J. GRAHAM
Gil C. Quiniones						Elisabeth J. Graham
Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ STEVEN J. CICHOCKI
Steven J. Cichocki
Director, Accounting (Principal Accounting Officer)

August 2, 2023

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PECO ENERGY COMPANY


/s/ MICHAEL A. INNOCENZO						/s/ MARISSA HUMPHREY
Michael A. Innocenzo						Marissa Humphrey
President, Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ CAROLINE FULGINITI
Caroline Fulginiti
Director, Accounting (Principal Accounting Officer)

August 2, 2023

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BALTIMORE GAS AND ELECTRIC COMPANY


/s/ CARIM V. KHOUZAMI						/s/ DAVID M. VAHOS
Carim V. Khouzami						David M. Vahos
President, Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ JASON T. JONES
Jason T. Jones
Director, Accounting (Principal Accounting Officer)

August 2, 2023

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PEPCO HOLDINGS LLC


/s/ J. TYLER ANTHONY						/s/ PHILLIP S. BARNETT
J. Tyler Anthony						Phillip S. Barnett
President, Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting (Principal Accounting Officer)

August 2, 2023

154

Table of Contents

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/ J. TYLER ANTHONY						/s/ PHILLIP S. BARNETT
J. Tyler Anthony						Phillip S. Barnett
President, Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer, Treasurer (Principal Financial Officer) and Director

/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting (Principal Accounting Officer)

August 2, 2023

155

Table of Contents

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/ J. TYLER ANTHONY						/s/ PHILLIP S. BARNETT
J. Tyler Anthony						Phillip S. Barnett
President, Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting (Principal Accounting Officer)

August 2, 2023

156

Table of Contents

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/ J. TYLER ANTHONY						/s/ PHILLIP S. BARNETT
J. Tyler Anthony						Phillip S. Barnett
President, Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting (Principal Accounting Officer)

August 2, 2023

157