EXC 10-Q Quarterly Report Sept. 30, 2025

EXELON CORP

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exc-20250930

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the Quarterly Period Ended September 30, 2025


☐ 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) 2301 Market Street P.O. Box 8699 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 20068-0001 (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

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 September 30, 2025 was:


Exelon Corporation Common Stock, without par value			1,010,290,316
Commonwealth Edison Company Common Stock, $12.50 par value			127,021,419
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		8
PART I.	FINANCIAL INFORMATION	9
ITEM 1.	FINANCIAL STATEMENTS	9
	Exelon Corporation
	Consolidated Statements of Operations and Comprehensive Income	10
	Consolidated Statements of Cash Flows	11
	Consolidated Balance Sheets	12
	Consolidated Statements of Changes in Shareholders’ Equity	14
	Commonwealth Edison Company
	Consolidated Statements of Operations and Comprehensive Income	16
	Consolidated Statements of Cash Flows	17
	Consolidated Balance Sheets	18
	Consolidated Statements of Changes in Shareholders' Equity	20
	PECO Energy Company
	Consolidated Statements of Operations and Comprehensive Income	21
	Consolidated Statements of Cash Flows	22
	Consolidated Balance Sheets	23
	Consolidated Statements of Changes in Shareholder's Equity	25
	Baltimore Gas and Electric Company
	Statements of Operations and Comprehensive Income	26
	Statements of Cash Flows	27
	Balance Sheets	28
	Statements of Changes in Shareholder's Equity	30
	Pepco Holdings LLC
	Consolidated Statements of Operations and Comprehensive Income	31
	Consolidated Statements of Cash Flows	32
	Consolidated Balance Sheets	33
	Consolidated Statements of Changes in Member's Equity	35


						Page No.
			Potomac Electric Power Company
			Statements of Operations and Comprehensive Income			36
			Statements of Cash Flows			37
			Balance Sheets			38
			Statements of Changes in Shareholder's Equity			40
			Delmarva Power & Light Company
			Statements of Operations and Comprehensive Income			41
			Statements of Cash Flows			42
			Balance Sheets			43
			Statements of Changes in Shareholder’s Equity			45
			Atlantic City Electric Company
			Consolidated Statements of Operations and Comprehensive Income			46
			Consolidated Statements of Cash Flows			47
			Consolidated Balance Sheets			48
			Consolidated Statements of Changes in Shareholder’s Equity			50
			Combined Notes to Consolidated Financial Statements
			1. Significant Accounting Policies			51
			2. Regulatory Matters			52
			3. Revenue from Contracts with Customers			60
			4. Segment Information			61
			5. Accounts Receivable			72

			6. Income Taxes			75
			7. Retirement Benefits			78
			8. Derivative Financial Instruments			80
			9. Debt and Credit Agreements			83
			10. Fair Value of Financial Assets and Liabilities			86
			11. Commitments and Contingencies			94
			12. Shareholders' Equity			100
			13. Changes in Accumulated Other Comprehensive Income			102

			14. Supplemental Financial Information			103
			15. Related Party Transactions			107


		Page No.


ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	109
	Exelon Corporation	109
	Executive Overview	109
	Financial Results of Operations	109
	Significant 2025 Transactions and Developments	111


	Other Key Business Drivers and Management Strategies	114
	Critical Accounting Policies and Estimates	115
	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	135
	Liquidity and Capital Resources	138

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	147
ITEM 4.	CONTROLS AND PROCEDURES	148
PART II.	OTHER INFORMATION	148
ITEM 1.	LEGAL PROCEEDINGS	148
ITEM 1A.	RISK FACTORS	148

ITEM 5.	OTHER INFORMATION	148
ITEM 6.	EXHIBITS	149
SIGNATURES		152
	Exelon Corporation	152
	Commonwealth Edison Company	153
	PECO Energy Company	154
	Baltimore Gas and Electric Company	155
	Pepco Holdings LLC	156
	Potomac Electric Power Company	157
	Delmarva Power & Light Company	158
	Atlantic City Electric Company	159

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 2024 Form 10-K						Reference to specific Combined Note to Consolidated Financial Statements within Exelon's 2024 Annual Report on Form 10-K
ABO						Accumulated Benefit Obligation
AFUDC						Allowance for Funds Used During Construction
AMI						Advanced Metering Infrastructure
AOCI						Accumulated Other Comprehensive Income (Loss)
ARO						Asset Retirement Obligation
ATM						At the market
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
DSIC						Distribution System Improvement Charge
EDIT						Excess Deferred Income Taxes
EPA						United States Environmental Protection Agency
ERISA						Employee Retirement Income Security Act of 1974, as amended
ETAC						Energy Transition Assistance Charge
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
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
MGP						Manufactured Gas Plant
mmcf						Million Cubic Feet
MRP						Multi-Year Rate Plan
MWh						Megawatt hour
N/A						Not Applicable
NAV						Net Asset Value

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
NJBPU						New Jersey Board of Public Utilities
NOLC						Tax Net Operating Loss Carryforward
NPNS						Normal Purchase Normal Sale scope exception
NPS						National Park Service
NRD						Natural Resources Damages
OBBBA						One Big Beautiful Bill Act
OCI						Other Comprehensive Income
OPEB						Other Postretirement Employee Benefits
PAPUC						Pennsylvania Public Utility Commission
PGC						Purchased Gas Cost Clause
PJM						PJM Interconnection, LLC
PLR						Private Letter Ruling
POLR						Provider of Last Resort
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 regulatory agreements with the ICC and PAPUC
Rider						Reconcilable Surcharge Recovery Mechanism
ROE						Return on Equity
ROU						Right-of-use
RTO						Regional Transmission Organization
RUBC						Residential Universal Bill Credit
SEC						United States Securities and Exchange Commission
SOFR						Secured Overnight Financing Rate
SOS						Standard Offer Service
TCJA						Tax Cuts and Jobs Act
TSC						Transmission Service Charge
ZEC						Zero Emission Credit

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 federal securities laws 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. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that may cause our actual results or outcomes to differ materially from those contained in our forward-looking statements, including, but not limited to:

• unfavorable legislative and/or regulatory actions;

• uncertainty as to outcomes and timing of regulatory approval proceedings and/or negotiated settlements thereof;

• environmental liabilities and remediation costs;

• state and federal legislation requiring use of low-emission, renewable, and/or alternate fuel sources and/or mandating implementation of energy conservation programs requiring implementation of new technologies;

• challenges to tax positions taken, tax law changes, and difficulty in quantifying potential tax effects of business decisions;

• negative outcomes in legal proceedings;

• adverse impact of the activities associated with the past DPA and now-resolved SEC investigation on Exelon’s and ComEd’s reputation and relationships with legislators, regulators, and customers;

• physical security and cybersecurity risks;

• extreme weather events, natural disasters, operational accidents such as wildfires or natural gas explosions, war, acts and threats of terrorism, public health crises, epidemics, pandemics, or other significant events;

• disruptions or cost increases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs;

• lack of sufficient capacity to meet actual or forecasted demand or disruptions at power generation facilities owned by third parties;

• emerging technologies that could affect or transform the energy industry;

• instability in capital and credit markets;

• a downgrade of any Registrant’s credit ratings or other failure to satisfy the credit standards in the Registrants’ agreements or regulatory financial requirements;

• significant economic downturns or increases in customer rates;

• impacts of climate change and weather on energy usage and maintenance and capital costs; and

Table of Contents

• impairment of long-lived assets, goodwill, and other assets.

New factors emerge from time to time, and it is impossible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see those factors discussed in the 2024 Form 10-K filed by the Registrants, including in Part I, ITEM 1A. Risk Factors, and this Report including in Part II, ITEM 1A. Risk Factors.

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 free of charge at 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 September 30,				Nine Months Ended September 30,
(In millions, except per share data)	2025		2024		2025		2024
Operating revenues
Electric operating revenues	$	6,690	$	6,012	$	17,872	$	16,379
Natural gas operating revenues	235		196		1,595		1,207
Revenues from alternative revenue programs	( 220 )		( 54 )		( 621 )		( 29 )
Total operating revenues	6,705		6,154		18,846		17,557
Operating expenses
Purchased power	2,645		2,349		6,640		6,483
Purchased fuel	47		34		471		301

Operating and maintenance	1,172		1,275		3,840		3,756
Depreciation and amortization	912		908		2,717		2,681
Taxes other than income taxes	429		395		1,216		1,127
Total operating expenses	5,205		4,961		14,884		14,348

Gain on sale of assets	—		3		1		12


Operating income	1,500		1,196		3,963		3,221
Other income and (deductions)
Interest expense, net	( 531 )		( 490 )		( 1,560 )		( 1,428 )
Interest expense to affiliates, net	( 7 )		( 6 )		( 18 )		( 18 )
Other, net	68		57		185		196
Total other income and (deductions)	( 470 )		( 439 )		( 1,393 )		( 1,250 )
Income before income taxes	1,030		757		2,570		1,971
Income taxes	155		50		396		158





Net income attributable to common shareholders	$	875	$	707	$	2,174	$	1,813






Comprehensive income, net of income taxes
Net income	$	875	$	707	$	2,174	$	1,813
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:

Actuarial losses reclassified to periodic benefit cost	5		5		16		15
Pension and non-pension postretirement benefit plans valuation adjustments	—		—		5		( 26 )
Unrealized (loss) gain on cash flow hedges	( 2 )		( 29 )		( 16 )		1



Other comprehensive income (loss)	3		( 24 )		5		( 10 )


Comprehensive income attributable to common shareholders	$	878	$	683	$	2,179	$	1,803

Average shares of common stock outstanding:
Basic	1,011		1,003		1,010		1,002
Assumed exercise and/or distributions of stock-based awards (a)	2		1		1		—
Diluted	1,013		1,004		1,011		1,002

Earnings per average common share
Basic	$	0.87	$	0.70	$	2.15	$	1.81
Diluted	$	0.86	$	0.70	$	2.15	$	1.81

__________

(a) The dilutive effects of stock-based compensation awards are calculated using the treasury stock method for all periods presented.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2025		2024
Cash flows from operating activities
Net income	$	2,174	$	1,813
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion	2,719		2,683


Gain on sales of assets	( 1 )		( 12 )

Deferred income taxes and amortization of investment tax credits	293		102
Net fair value changes related to derivatives	3		1


Other non-cash operating activities	1,088		441
Changes in assets and liabilities:
Accounts receivable	( 422 )		( 489 )
Inventories	( 41 )		( 57 )
Accounts payable and accrued expenses	165		( 309 )

Collateral (paid) received, net	( 25 )		21
Income taxes	19		( 18 )
Regulatory assets and liabilities, net	( 390 )		194
Pension and non-pension postretirement benefit contributions	( 313 )		( 140 )
Other assets and liabilities	( 259 )		( 87 )
Net cash flows provided by operating activities	5,010		4,143
Cash flows from investing activities
Capital expenditures	( 6,095 )		( 5,161 )





Proceeds from sales of assets	2		38


Other investing activities	( 7 )		9
Net cash flows used in investing activities	( 6,100 )		( 5,114 )
Cash flows from financing activities
Changes in short-term borrowings	( 779 )		( 1,093 )
Proceeds from short-term borrowings with maturities greater than 90 days	—		150
Repayments on short-term borrowings with maturities greater than 90 days	—		( 549 )
Issuance of long-term debt	4,925		4,975
Retirement of long-term debt	( 807 )		( 1,336 )

Issuance of common stock	173		148



Dividends paid on common stock	( 1,212 )		( 1,142 )
Proceeds from employee stock plans	24		33

Other financing activities	( 75 )		( 83 )
Net cash flows provided by financing activities	2,249		1,103
Increase in cash, restricted cash, and cash equivalents	1,159		132
Cash, restricted cash, and cash equivalents at beginning of period	939		1,101
Cash, restricted cash, and cash equivalents at end of period	$	2,098	$	1,233

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	( 12 )		6

(Decrease) increase in PP&E related to ARO update	( 5 )		16

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
ASSETS
Current assets
Cash and cash equivalents	$	1,533	$	357
Restricted cash and cash equivalents	516		541

Accounts receivable
Customer accounts receivable	3,356		3,144
Customer allowance for credit losses	( 451 )		( 406 )
Customer accounts receivable, net	2,905		2,738
Other accounts receivable	1,192		1,123
Other allowance for credit losses	( 98 )		( 107 )
Other accounts receivable, net	1,094		1,016
Inventories, net
Fossil fuel	100		72
Materials and supplies	788		781
Regulatory assets	1,489		1,940
Prepaid renewable energy credits	445		494
Other	359		445
Total current assets	9,229		8,384
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 19,606 and $ 18,445 as of September 30, 2025 and December 31, 2024, respectively)	82,100		78,182
Deferred debits and other assets
Regulatory assets	8,881		8,710
Goodwill	6,630		6,630
Receivable related to Regulatory Agreement Units	4,658		4,026
Investments	307		290
Other	1,734		1,562
Total deferred debits and other assets	22,210		21,218
Total assets	$	113,539	$	107,784

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	1,080	$	1,859
Long-term debt due within one year	2,168		1,453
Accounts payable	3,240		2,994
Accrued expenses	1,414		1,468
Payables to affiliates	5		5
Customer deposits	507		446
Regulatory liabilities	507		411
Mark-to-market derivative liabilities	28		29
Unamortized energy contract liabilities	5		5
Renewable energy credit obligations	352		429
Other	519		512
Total current liabilities	9,825		9,611
Long-term debt	46,283		42,947
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	13,519		12,793
Regulatory liabilities	10,904		10,198
Pension obligations	1,480		1,745
Non-pension postretirement benefit obligations	493		472
Asset retirement obligations	303		301
Mark-to-market derivative liabilities	109		103
Unamortized energy contract liabilities	18		21
Other	2,102		2,282
Total deferred credits and other liabilities	28,928		27,915
Total liabilities	85,426		80,863
Commitments and contingencies

Shareholders’ equity
Common stock ( No par value, 2,000 shares authorized, 1,010 shares and 1,005 shares outstanding as of September 30, 2025 and December 31, 2024, respectively)	21,564		21,338
Treasury stock, at cost ( 2 shares as of September 30, 2025 and December 31, 2024)	( 123 )		( 123 )
Retained earnings	7,387		6,426
Accumulated other comprehensive loss, net	( 715 )		( 720 )
Total shareholders’ equity	28,113		26,921


Total liabilities and shareholders’ equity	$	113,539	$	107,784

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Exelon Corporation and Subsidiary Companies

Consolidated Statements of Changes in Shareholders' Equity

(Unaudited)


	Nine Months Ended September 30, 2025
(In millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Loss, net		Total Shareholders' Equity
Balance at December 31, 2024	1,007,046	$	21,338	$	( 123 )	$	6,426	$	( 720 )	$	26,921
Net income	—	—		—		908		—		908
Long-term incentive plan activity	299	4		—		—		—		4
Employee stock purchase plan activity	( 8 )	2		—		—		—		2
Issuance of Common Stock	4,031	173		—		—		—		173



Common stock dividends ($ 0.40 /common share)	—	—		—		( 403 )		—		( 403 )
Other comprehensive income, net of income taxes	—	—		—		—		2		2

Balance at March 31, 2025	1,011,368	$	21,517	$	( 123 )	$	6,931	$	( 718 )	$	27,607
Net income	—	—		—		391		—		391
Long-term incentive plan activity	118	14		—		—		—		14
Employee stock purchase plan activity	334	13		—		—		—		13




Common stock dividends ($ 0.40 /common share)	—	—		—		( 405 )		—		( 405 )


Balance at June 30, 2025	1,011,820	$	21,544	$	( 123 )	$	6,917	$	( 718 )	$	27,620
Net income	—	—		—		875		—		875
Long-term incentive plan activity	4	6		—		—		—		6
Employee stock purchase plan activity	299	14		—		—		—		14



Common stock dividends ($ 0.40 /common share)	—	—		—		( 405 )		—		( 405 )
Other comprehensive income, net of income taxes	—	—		—		—		3		3
Balance at September 30, 2025	1,012,123	$	21,564	$	( 123 )	$	7,387	$	( 715 )	$	28,113

See the Combined Notes to Consolidated Financial Statements

Table of Contents


	Nine Months Ended September 30, 2024
(In millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Loss, net		Total Shareholders' Equity
Balance at December 31, 2023	1,001,249	$	21,114	$	( 123 )	$	5,490	$	( 726 )	$	25,755
Net income	—	—		—		658		—		658
Long-term incentive plan activity	333	2		—		—		—		2
Employee stock purchase plan activity	276	13		—		—		—		13




Common stock dividends ($ 0.38 /common share)	—	—		—		( 381 )		—		( 381 )
Other comprehensive income, net of income taxes	—	—		—		—		14		14

Balance at March 31, 2024	1,001,858	$	21,129	$	( 123 )	$	5,767	$	( 712 )	$	26,061
Net income	—	—		—		448		—		448
Long-term incentive plan activity	76	11		—		—		—		11
Employee stock purchase plan activity	396	12		—		—		—		12



Common stock dividends ($ 0.38 /common share)	—	—		—		( 380 )		—		( 380 )

Balance at June 30, 2024	1,002,330	$	21,152	$	( 123 )	$	5,835	$	( 712 )	$	26,152
Net Income	—	—		—		707		—		707
Long-term incentive plan activity	7	7		—		—		—		7
Employee stock purchase plan activity	349	13		—		—		—		13
Issuance of common stock	3,980	148				—				148



Common stock dividends ($ 0.38 /common share)	—	—		—		( 381 )		—		( 381 )
Other comprehensive income, net of income taxes	—	—		—		—		( 24 )		( 24 )
Balance at September 30, 2024	1,006,666	$	21,320	$	( 123 )	$	6,161	$	( 736 )	$	26,622

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 September 30,				Nine Months Ended September 30,
(In millions)	2025		2024		2025		2024
Operating revenues
Electric operating revenues	$	2,479	$	2,303	$	6,682	$	6,497
Revenues from alternative revenue programs	( 206 )		( 76 )		( 525 )		( 100 )
Operating revenues from affiliates	2		2		19		6
Total operating revenues	2,275		2,229		6,176		6,403
Operating expenses
Purchased power	806		835		2,044		2,504

Operating and maintenance	313		307		958		970
Operating and maintenance from affiliates	96		103		296		307
Depreciation and amortization	395		387		1,162		1,124
Taxes other than income taxes	107		99		303		287
Total operating expenses	1,717		1,731		4,763		5,192
Gain on sale of assets	—		—		—		5
Operating income	558		498		1,413		1,216
Other income and (deductions)
Interest expense, net	( 132 )		( 125 )		( 385 )		( 364 )
Interest expense to affiliates, net	( 3 )		( 3 )		( 10 )		( 10 )
Other, net	33		26		86		66
Total other income and (deductions)	( 102 )		( 102 )		( 309 )		( 308 )
Income before income taxes	456		396		1,104		908
Income taxes	83		36		201		85
Net income	$	373	$	360	$	903	$	823
Comprehensive income	$	373	$	360	$	903	$	823

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Commonwealth Edison Company and Subsidiary Companies

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2025		2024
Cash flows from operating activities
Net income	$	903	$	823
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	1,162		1,124
Gain on sales of assets	—		( 5 )
Deferred income taxes and amortization of investment tax credits	21		( 16 )

Other non-cash operating activities	634		161
Changes in assets and liabilities:
Accounts receivable	( 347 )		( 327 )
Receivables from and payables to affiliates, net	( 16 )		43
Inventories	12		( 17 )
Accounts payable and accrued expenses	112		( 207 )
Collateral (paid) received, net	( 31 )		21
Income taxes	66		( 109 )
Regulatory assets and liabilities, net	( 128 )		422
Pension and non-pension postretirement benefit contributions	( 192 )		( 11 )
Other assets and liabilities	( 136 )		134
Net cash flows provided by operating activities	2,060		2,036
Cash flows from investing activities
Capital expenditures	( 1,970 )		( 1,619 )




Other investing activities	5		8
Net cash flows used in investing activities	( 1,965 )		( 1,611 )
Cash flows from financing activities
Changes in short-term borrowings	( 36 )		( 129 )

Repayments on short-term borrowings with maturities greater than 90 days	—		( 400 )
Issuance of long-term debt	725		800
Retirement of long-term debt	—		( 250 )
Dividends paid on common stock	( 610 )		( 582 )
Contributions from parent	108		117
Other financing activities	( 7 )		( 12 )
Net cash flows provided by (used in) financing activities	180		( 456 )
Increase (decrease) in cash, restricted cash, and cash equivalents	275		( 31 )
Cash, restricted cash, and cash equivalents at beginning of period	632		686
Cash, restricted cash, and cash equivalents at end of period	$	907	$	655

Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	74	$	( 31 )

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
ASSETS
Current assets
Cash and cash equivalents	$	405	$	105
Restricted cash and cash equivalents	453		486
Accounts receivable
Customer accounts receivable	1,205		994
Customer allowance for credit losses	( 115 )		( 109 )
Customer accounts receivable, net	1,090		885
Other accounts receivable	353		290
Other allowance for credit losses	( 25 )		( 34 )
Other accounts receivable, net	328		256

Receivables from affiliates	4		4

Inventories, net	274		292

Regulatory assets	705		1,159

Other	201		141
Total current assets	3,460		3,328
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 8,134 and $ 7,619 as of September 30, 2025 and December 31, 2024, respectively)	31,446		30,211
Deferred debits and other assets
Regulatory assets	2,646		2,562

Goodwill	2,625		2,625

Receivable related to Regulatory Agreement Units	4,231		3,780
Investments	7		6
Prepaid pension asset	1,301		1,165

Other	1,294		1,073
Total deferred debits and other assets	12,104		11,211
Total assets	$	47,010	$	44,750

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Commonwealth Edison Company and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	—	$	36
Long-term debt due within one year	500		—
Accounts payable	992		748
Accrued expenses	460		463
Payables to affiliates	61		77
Customer deposits	178		134
Regulatory liabilities	221		197
Mark-to-market derivative liabilities	28		29

Other	278		270
Total current liabilities	2,718		1,954
Long-term debt	12,251		12,030
Long-term debt to financing trust	206		206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	5,773		5,601
Regulatory liabilities	9,041		8,421
Asset retirement obligations	172		167

Non-pension postretirement benefit obligations	164		156

Mark-to-market derivative liabilities	100		103

Other	1,304		1,232
Total deferred credits and other liabilities	16,554		15,680
Total liabilities	31,729		29,870
Commitments and contingencies
Shareholders’ equity
Common stock	1,588		1,588


Other paid-in capital	10,736		10,628
Retained earnings	2,957		2,664

Total shareholders’ equity	15,281		14,880
Total liabilities and shareholders’ equity	$	47,010	$	44,750

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)


	Nine Months Ended September 30, 2025
(In millions)	Common Stock		Other Paid-In Capital		Retained Earnings		Total Shareholders’ Equity
Balance at December 31, 2024	$	1,588	$	10,628	$	2,664	$	14,880
Net income	—		—		302		302
Common stock dividends	—		—		( 203 )		( 203 )
Contributions from parent	—		87		—		87
Balance at March 31, 2025	$	1,588	$	10,715	$	2,763	$	15,066
Net income	—		—		228		228
Common stock dividends	—		—		( 204 )		( 204 )
Contributions from parent	—		—		—		—
Balance at June 30, 2025	$	1,588	$	10,715	$	2,787	$	15,090
Net income	—		—		373		373
Common stock dividends	—		—		( 203 )		( 203 )
Contributions from parent	—		21		—		21
Balance at September 30, 2025	$	1,588	$	10,736	$	2,957	$	15,281

	Nine Months Ended September 30, 2024
(In millions)	Common Stock		Other Paid-In Capital		Retained Earnings		Total Shareholders’ Equity
Balance at December 31, 2023	$	1,588	$	10,401	$	2,374	$	14,363
Net income	—		—		193		193
Common stock dividends	—		—		( 194 )		( 194 )
Contributions from parent	—		39		—		39
Balance at March 31, 2024	$	1,588	$	10,440	$	2,373	$	14,401
Net income	—		—		270		270
Common stock dividends	—		—		( 194 )		( 194 )
Contributions from parent	—		39		—		39
Balance at June 30, 2024	$	1,588	$	10,479	$	2,449	$	14,516
Net income	—		—		360		360
Common stock dividends	—		—		( 194 )		( 194 )
Contributions from parent	—		39		—		39
Balance at September 30, 2024	$	1,588	$	10,518	$	2,615	$	14,721

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 September 30,				Nine Months Ended September 30,
(In millions)	2025		2024		2025		2024
Operating revenues
Electric operating revenues	$	1,093	$	952	$	2,932	$	2,529
Natural gas operating revenues	82		69		578		436
Revenues from alternative revenue programs	2		5		( 6 )		3
Operating revenues from affiliates	3		4		9		7
Total operating revenues	1,180		1,030		3,513		2,975
Operating expenses
Purchased power	428		372		1,093		977
Purchased fuel	18		14		195		136

Operating and maintenance	183		251		690		695
Operating and maintenance from affiliates	58		62		182		181
Depreciation and amortization	115		108		336		318
Taxes other than income taxes	69		61		183		164
Total operating expenses	871		868		2,679		2,471
Gain on sales of assets	—		—		—		4
Operating income	309		162		834		508
Other income and (deductions)
Interest expense, net	( 63 )		( 55 )		( 179 )		( 161 )
Interest expense to affiliates, net	( 2 )		( 3 )		( 9 )		( 9 )
Other, net	11		9		29		27
Total other income and (deductions)	( 54 )		( 49 )		( 159 )		( 143 )
Income before income taxes	255		113		675		365
Income taxes	5		( 4 )		23		9

Net income	$	250	$	117	$	652	$	356
Comprehensive income	$	250	$	117	$	652	$	356

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2025		2024
Cash flows from operating activities
Net income	$	652	$	356
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	336		318

Gain on sales of assets	—		( 4 )
Deferred income taxes and amortization of investment tax credits	( 60 )		( 27 )
Other non-cash operating activities	69		58
Changes in assets and liabilities:
Accounts receivable	( 94 )		( 75 )
Receivables from and payables to affiliates, net	( 8 )		( 2 )
Inventories	( 8 )		( 2 )
Accounts payable and accrued expenses	( 4 )		( 65 )
Collateral (paid) received, net	6		—
Income taxes	13		( 55 )
Regulatory assets and liabilities, net	( 26 )		17
Pension and non-pension postretirement benefit contributions	( 11 )		( 3 )
Other assets and liabilities	( 10 )		( 19 )
Net cash flows provided by operating activities	855		497
Cash flows from investing activities
Capital expenditures	( 1,334 )		( 1,125 )
Changes in Exelon intercompany money pool	( 222 )		( 89 )

Other investing activities	1		5
Net cash flows used in investing activities	( 1,555 )		( 1,209 )
Cash flows from financing activities

Changes in short-term borrowings	( 192 )		( 165 )
Issuance of long-term debt	1,050		575



Dividends paid on common stock	( 410 )		( 300 )
Contributions from parent	578		595


Other financing activities	( 10 )		( 7 )
Net cash flows provided by financing activities	1,016		698
Increase (decrease) in cash, restricted cash, and cash equivalents	316		( 14 )
Cash, restricted cash, and cash equivalents at beginning of period	48		51
Cash, restricted cash, and cash equivalents at end of period	$	364	$	37

Supplemental cash flow information
Increase in capital expenditures not paid	$	81	$	60

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
ASSETS
Current assets
Cash and cash equivalents	$	364	$	48

Accounts receivable
Customer accounts receivable	697		670
Customer allowance for credit losses	( 145 )		( 133 )
Customer accounts receivable, net	552		537
Other accounts receivable	156		145
Other allowance for credit losses	( 17 )		( 18 )
Other accounts receivable, net	139		127

Receivables from affiliates	2		—
Receivable from Exelon intercompany money pool	222		—

Inventories, net
Fossil fuel	46		37
Materials and supplies	76		79
Prepaid utility taxes	18		2
Prepaid renewable energy credits	36		51
Regulatory assets	66		65

Other	31		27
Total current assets	1,552		973
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,080 and $ 4,042 as of September 30, 2025 and December 31, 2024, respectively)	15,490		14,392
Deferred debits and other assets
Regulatory assets	1,231		1,003




Receivable related to Regulatory Agreement Units	428		247
Investments	43		41
Prepaid pension asset	443		435

Other	40		32
Total deferred debits and other assets	2,185		1,758
Total assets	$	19,227	$	17,123

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO Energy Company and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	192
Long-term debt due within one year	350		350
Accounts payable	753		639
Accrued expenses	150		166
Payables to affiliates	35		41

Customer deposits	87		80
Renewable energy credit obligations	37		52
Regulatory liabilities	154		122


Other	50		28
Total current liabilities	1,616		1,670
Long-term debt	6,396		5,354
Long-term debt to financing trusts	184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,557		2,433
Regulatory liabilities	433		253
Asset retirement obligations	26		27
Non-pension postretirement benefit obligations	288		287





Other	92		100
Total deferred credits and other liabilities	3,396		3,100
Total liabilities	11,592		10,308
Commitments and contingencies
Shareholder’s equity
Common stock	5,223		4,645


Retained earnings	2,412		2,170


Total shareholder’s equity	7,635		6,815
Total liabilities and shareholder's equity	$	19,227	$	17,123

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO Energy Company and Subsidiary Companies

Consolidated Statements of Changes in Shareholders' Equity

(Unaudited)


	Nine Months Ended September 30, 2025
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2024	$	4,645	$	2,170	$	6,815
Net income	—		266		266
Common stock dividends	—		( 137 )		( 137 )
Contributions from parent	563		—		563
Balance at March 31, 2025	$	5,208	$	2,299	$	7,507
Net income	—		136		136
Common stock dividends	—		( 136 )		( 136 )
Contributions from parent	—		—		—
Balance at June 30, 2025	$	5,208	$	2,299	$	7,507
Net income	—		250		250
Common stock dividends	—		( 137 )		( 137 )
Contributions from parent	15		—		15
Balance at September 30, 2025	$	5,223	$	2,412	$	7,635

	Nine Months Ended September 30, 2024
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2023	$	4,050	$	2,019	$	6,069
Net income	—		149		149
Common stock dividends	—		( 100 )		( 100 )
Contributions from parent	580		—		580
Balance at March 31, 2024	$	4,630	$	2,068	$	6,698
Net income	—		90		90
Common stock dividends	—		( 100 )		( 100 )

Balance at June 30, 2024	$	4,630	$	2,058	$	6,688
Net income	—		117		117
Common stock dividends	—		( 100 )		( 100 )
Contributions from parent	15		—		15
Balance at September 30, 2024	$	4,645	$	2,075	$	6,720

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 September 30,				Nine Months Ended September 30,
(In millions)	2025		2024		2025		2024
Operating revenues
Electric operating revenues	$	1,102	$	928	$	2,978	$	2,585
Natural gas operating revenues	125		104		870		648
Revenues from alternative revenue programs	( 20 )		9		( 63 )		28
Operating revenues from affiliates	2		3		6		7
Total operating revenues	1,209		1,044		3,791		3,268
Operating expenses
Purchased power	547		407		1,365		1,108
Purchased fuel	21		13		219		120

Operating and maintenance	179		221		621		613
Operating and maintenance from affiliates	60		60		186		182
Depreciation and amortization	155		162		473		474
Taxes other than income taxes	93		86		273		254
Total operating expenses	1,055		949		3,137		2,751

Operating income	154		95		654		517
Other income and (deductions)
Interest expense, net	( 64 )		( 57 )		( 183 )		( 159 )
Other, net	15		11		35		27
Total other income and (deductions)	( 49 )		( 46 )		( 148 )		( 132 )
Income before income taxes	105		49		506		385
Income taxes	23		4		108		32
Net income	$	82	$	45	$	398	$	353
Comprehensive income	$	82	$	45	$	398	$	353

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Baltimore Gas and Electric Company

Statements of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2025		2024
Cash flows from operating activities
Net income	$	398	$	353
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	473		474

Deferred income taxes and amortization of investment tax credits	53		( 5 )

Other non-cash operating activities	127		49
Changes in assets and liabilities:
Accounts receivable	34		25
Receivables from and payables to affiliates, net	( 15 )		14
Inventories	( 10 )		( 6 )
Accounts payable and accrued expenses	88		37
Collateral received, net	2		—
Income taxes	19		( 51 )
Regulatory assets and liabilities, net	( 114 )		( 69 )
Pension and non-pension postretirement benefit contributions	( 40 )		( 34 )
Other assets and liabilities	116		102
Net cash flows provided by operating activities	1,131		889
Cash flows from investing activities
Capital expenditures	( 1,211 )		( 1,033 )

Other investing activities	7		10
Net cash flows used in investing activities	( 1,204 )		( 1,023 )
Cash flows from financing activities
Changes in short-term borrowings	( 175 )		( 336 )
Issuance of long-term debt	650		800



Dividends paid on common stock	( 294 )		( 276 )
Contributions from parent	531		237
Other financing activities	( 8 )		( 9 )
Net cash flows provided by financing activities	704		416
Increase in cash, restricted cash, and cash equivalents	631		282
Cash, restricted cash, and cash equivalents at beginning of period	34		48
Cash, restricted cash, and cash equivalents at end of period	$	665	$	330

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	( 46 )	$	38

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Baltimore Gas and Electric Company

Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
ASSETS
Current assets
Cash and cash equivalents	$	663	$	33
Restricted cash and cash equivalents	2		1
Accounts receivable
Customer accounts receivable	625		654
Customer allowance for credit losses	( 68 )		( 56 )
Customer accounts receivable, net	557		598
Other accounts receivable	91		113
Other allowance for credit losses	( 5 )		( 6 )
Other accounts receivable, net	86		107

Receivables from affiliates	1		—


Inventories, net
Fossil fuel	45		29
Materials and supplies	78		84
Prepaid utility taxes	1		115
Regulatory assets	199		207
Prepaid renewable energy credits	143		157
Other	18		17
Total current assets	1,793		1,348
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 5,132 and $ 5,005 as of September 30, 2025 and December 31, 2024, respectively)	13,890		13,134
Deferred debits and other assets
Regulatory assets	799		788
Investments	10		10


Prepaid pension asset	206		218

Other	44		44
Total deferred debits and other assets	1,059		1,060
Total assets	$	16,742	$	15,542

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Baltimore Gas and Electric Company

Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	175
Long-term debt due within one year	350		—
Accounts payable	483		515
Accrued expenses	263		176
Payables to affiliates	33		48
Customer deposits	122		118
Regulatory liabilities	6		12

Renewable energy credit obligations	146		160
Other	45		39
Total current liabilities	1,448		1,243
Long-term debt	5,691		5,395
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,193		2,099
Regulatory liabilities	614		636
Asset retirement obligations	36		36
Non-pension postretirement benefit obligations	144		150



Other	96		97
Total deferred credits and other liabilities	3,083		3,018
Total liabilities	10,222		9,656
Commitments and contingencies
Shareholder's equity
Common stock	4,014		3,483

Retained earnings	2,506		2,403


Total shareholder's equity	6,520		5,886


Total liabilities and shareholder's equity	$	16,742	$	15,542

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Baltimore Gas and Electric Company

Statements of Changes in Shareholder's Equity

(Unaudited)


	Nine Months Ended September 30, 2025
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2024	$	3,483	$	2,403	$	5,886
Net income	—		260		260
Common stock dividends	—		( 98 )		( 98 )
Contributions from parent	—		—		—
Balance at March 31, 2025	$	3,483	$	2,565	$	6,048
Net income	—		55		55
Common stock dividends	—		( 98 )		( 98 )
Contributions from parent	—		—		—
Balance at June 30, 2025	$	3,483	$	2,522	$	6,005
Net income	—		82		82
Common stock dividends	—		( 98 )		( 98 )
Contributions from parent	531		—		531
Balance at September 30, 2025	$	4,014	$	2,506	$	6,520

	Nine Months Ended September 30, 2024
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2023	$	3,246	$	2,244	$	5,490
Net income	—		264		264
Common stock dividends	—		( 92 )		( 92 )
Contributions from parent	—		—		—
Balance at March 31, 2024	$	3,246	$	2,416	$	5,662
Net income	—		44		44
Common stock dividends	—		( 92 )		( 92 )
Contributions from parent	197		—		197
Balance at June 30, 2024	$	3,443	$	2,368	$	5,811
Net income	—		45		45
Common stock dividends	—		( 92 )		( 92 )
Contributions from parent	40		—		40
Balance at September 30, 2024	$	3,483	$	2,321	$	5,804

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 September 30,				Nine Months Ended September 30,
(In millions)	2025		2024		2025		2024
Operating revenues
Electric operating revenues	$	2,016	$	1,828	$	5,280	$	4,769
Natural gas operating revenues	27		23		148		122
Revenues from alternative revenue programs	6		8		( 27 )		40
Operating revenues from affiliates	2		3		7		7
Total operating revenues	2,051		1,862		5,408		4,938
Operating expenses
Purchased power	864		735		2,138		1,895
Purchased fuel	8		7		57		44

Operating and maintenance	290		275		876		780
Operating and maintenance from affiliates	45		47		148		147
Depreciation and amortization	234		235		701		716
Taxes other than income taxes	150		140		426		395
Total operating expenses	1,591		1,439		4,346		3,977

Gain on sale of assets	—		—		1		—
Operating income	460		423		1,063		961
Other income and (deductions)
Interest expense, net	( 102 )		( 95 )		( 303 )		( 279 )
Interest expense to affiliates, net	—		—		( 2 )		—
Other, net	18		22		54		79
Total other income and (deductions)	( 84 )		( 73 )		( 251 )		( 200 )
Income before income taxes	376		350		812		761
Income taxes	85		72		184		158

Net income	$	291	$	278	$	628	$	603








Comprehensive income	$	291	$	278	$	628	$	603

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Pepco Holdings LLC and Subsidiary Companies

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2025		2024
Cash flows from operating activities
Net income	$	628	$	603
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion	703		716

Gain on sales of assets	( 1 )		—
Deferred income taxes and amortization of investment tax credits	93		56

Other non-cash operating activities	172		96
Changes in assets and liabilities:
Accounts receivable	( 28 )		( 116 )
Receivables from and payables to affiliates, net	( 17 )		( 8 )
Inventories	( 36 )		( 32 )
Accounts payable and accrued expenses	21		37

Collateral received, net	1		1
Income taxes	( 13 )		( 55 )
Regulatory assets and liabilities, net	( 88 )		( 158 )
Pension and non-pension postretirement benefit contributions	( 47 )		( 79 )
Other assets and liabilities	( 20 )		( 74 )
Net cash flows provided by operating activities	1,368		987
Cash flows from investing activities
Capital expenditures	( 1,552 )		( 1,343 )
Proceeds from sales of long-lived assets	2		—




Net cash flows used in investing activities	( 1,550 )		( 1,343 )
Cash flows from financing activities
Changes in short-term borrowings	( 364 )		( 176 )


Issuance of long-term debt	500		1,100
Retirement of long-term debt	—		( 583 )
Changes in Exelon intercompany money pool	1		10



Distributions to member	( 548 )		( 549 )
Contributions from member	569		505


Other financing activities	( 19 )		( 33 )
Net cash flows provided by financing activities	139		274
Decrease in cash, restricted cash, and cash equivalents	( 43 )		( 82 )
Cash, restricted cash, and cash equivalents at beginning of period	163		204
Cash, restricted cash, and cash equivalents at end of period	$	120	$	122

Supplemental cash flow information
Decrease in capital expenditures not paid	$	( 92 )	$	( 27 )

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Pepco Holdings LLC and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
ASSETS
Current assets
Cash and cash equivalents	$	93	$	139
Restricted cash and cash equivalents	27		24
Accounts receivable
Customer accounts receivable	829		827
Customer allowance for credit losses	( 123 )		( 108 )
Customer accounts receivable, net	706		719
Other accounts receivable	281		284
Other allowance for credit losses	( 51 )		( 49 )
Other accounts receivable, net	230		235

Receivables from affiliates	13		8


Inventories, net
Fossil fuel	9		7
Materials and supplies	360		325

Prepaid utility taxes	17		70
Regulatory assets	333		323

Prepaid renewable energy credits	155		194
Other	31		36
Total current assets	1,974		2,080
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,196 and $ 3,728 as of September 30, 2025 and December 31, 2024, respectively)	20,925		20,053
Deferred debits and other assets
Regulatory assets	1,531		1,570
Goodwill	4,005		4,005
Investments	156		152


Prepaid pension asset	222		252


Other	134		185
Total deferred debits and other assets	6,048		6,164
Total assets	$	28,947	$	28,297

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Pepco Holdings LLC and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings	$	166	$	530
Long-term debt due within one year	214		290
Accounts payable	671		721
Accrued expenses	343		367
Payables to affiliates	54		66
Borrowings from Exelon intercompany money pool	64		63

Customer deposits	120		113
Regulatory liabilities	115		69
Unamortized energy contract liabilities	5		5


Renewable energy credit obligations	169		217
Other	97		124
Total current liabilities	2,018		2,565
Long-term debt	9,385		8,834
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	3,337		3,190
Regulatory liabilities	731		794
Asset retirement obligations	65		67
Non-pension postretirement benefit obligations	26		31




Unamortized energy contract liabilities	17		21
Other	397		473
Total deferred credits and other liabilities	4,573		4,576
Total liabilities	15,976		15,975
Commitments and contingencies

Member's equity
Membership interest	13,131		12,562

Undistributed losses	( 160 )		( 240 )

Total member's equity	12,971		12,322
Total liabilities and member's equity	$	28,947	$	28,297

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)


	Nine Months Ended September 30, 2025
(In millions)	Membership Interest		Undistributed (Losses)/Gains		Total Member's Equity
Balance at December 31, 2024	$	12,562	$	( 240 )	$	12,322
Net income	—		194		194
Distributions to member	—		( 132 )		( 132 )
Contributions from member	352		—		352
Balance at March 31, 2025	$	12,914	$	( 178 )	$	12,736
Net income	—		143		143
Distributions to member	—		( 160 )		( 160 )
Contributions from member	170		—		170
Balance at June 30, 2025	$	13,084	$	( 195 )	$	12,889
Net income	—		291		291
Distributions to member	—		( 256 )		( 256 )
Contributions from member	47		—		47

Balance at September 30, 2025	$	13,131	$	( 160 )	$	12,971


	Nine Months Ended September 30, 2024
(In millions)	Membership Interest		Undistributed (Losses)/Gains		Total Member's Equity
Balance at December 31, 2023	$	12,057	$	( 275 )	$	11,782
Net income	—		168		168
Distributions to member	—		( 118 )		( 118 )
Contributions from member	487		—		487
Balance at March 31, 2024	$	12,544	$	( 225 )	$	12,319
Net income	—		158		158
Distributions to member	—		( 164 )		( 164 )
Contributions from member	—		—		—
Balance at June 30, 2024	$	12,544	$	( 231 )	$	12,313
Net income	—		278		278
Distributions to member	—		( 267 )		( 267 )
Contributions from member	18		—		18
Balance at September 30, 2024	$	12,562	$	( 220 )	$	12,342

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 September 30,				Nine Months Ended September 30,
(In millions)	2025		2024		2025		2024
Operating revenues
Electric operating revenues	$	995	854		$	2,641	$	2,273
Revenues from alternative revenue programs	( 5 )		5		( 19 )		42
Operating revenues from affiliates	2		2		4		5
Total operating revenues	992		861		2,626		2,320
Operating expenses
Purchased power	367		294		942		808

Operating and maintenance	95		82		282		206
Operating and maintenance from affiliates	59		58		184		186
Depreciation and amortization	110		102		321		307
Taxes other than income taxes	122		114		344		317
Total operating expenses	753		650		2,073		1,824

Gain on sale of assets	—		—		1		—

Operating income	239		211		554		496
Other income and (deductions)
Interest expense, net	( 53 )		( 50 )		( 159 )		( 142 )

Other, net	11		11		31		43
Total other income and (deductions)	( 42 )		( 39 )		( 128 )		( 99 )
Income before income taxes	197		172		426		397
Income taxes	41		32		89		74

Net income	$	156	$	140	$	337	$	323










Comprehensive income	$	156	$	140	$	337	$	323

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Potomac Electric Power Company

Statements Of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2025		2024
Cash flows from operating activities
Net income	$	337	$	323
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion	322		307
Gain on sales of assets	( 1 )		—
Deferred income taxes and amortization of investment tax credits	34		22

Other non-cash operating activities	62		( 11 )
Changes in assets and liabilities:
Accounts receivable	( 58 )		( 37 )
Receivables from and payables to affiliates, net	—		1
Inventories	( 11 )		( 10 )
Accounts payable and accrued expenses	20		61
Collateral received (paid), net	2		( 1 )
Income taxes	( 27 )		( 45 )
Regulatory assets and liabilities, net	( 39 )		( 54 )
Pension and non-pension postretirement benefit contributions	( 7 )		( 7 )
Other assets and liabilities	( 5 )		( 56 )
Net cash flows provided by operating activities	629		493
Cash flows from investing activities
Capital expenditures	( 690 )		( 672 )
Proceeds from sales of long-lived assets	2		—




Net cash flows used in investing activities	( 688 )		( 672 )
Cash flows from financing activities
Changes in short-term borrowings	( 137 )		( 83 )
Issuance of long-term debt	275		675
Retirement of long-term debt	—		( 400 )

Dividends paid on common stock	( 267 )		( 286 )
Contributions from parent	192		260


Other financing activities	( 8 )		( 19 )
Net cash flows provided by financing activities	55		147
Decrease in cash, restricted cash, and cash equivalents	( 4 )		( 32 )
Cash, restricted cash, and cash equivalents at beginning of period	51		72
Cash, restricted cash, and cash equivalents at end of period	$	47	$	40

Supplemental cash flow information
Decrease in capital expenditures not paid	$	( 34 )	$	( 27 )

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Potomac Electric Power Company

Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
ASSETS
Current assets
Cash and cash equivalents	$	25	$	30
Restricted cash and cash equivalents	22		21
Accounts receivable
Customer accounts receivable	431		395
Customer allowance for credit losses	( 72 )		( 59 )
Customer accounts receivable, net	359		336
Other accounts receivable	149		142
Other allowance for credit losses	( 28 )		( 27 )
Other accounts receivable, net	121		115

Receivables from affiliates	1		1


Inventories, net	181		169



Regulatory assets	166		157

Prepaid renewable energy credits	132		165
Other	21		55
Total current assets	1,028		1,049
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 4,719 and $ 4,522 as of September 30, 2025 and December 31, 2024, respectively)	10,493		10,097
Deferred debits and other assets
Regulatory assets	408		446
Investments	139		135



Prepaid pension asset	201		222

Other	57		51
Total deferred debits and other assets	805		854
Total assets	$	12,326	$	12,000

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Potomac Electric Power Company

Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	63	$	200
Long-term debt due within one year	6		6
Accounts payable	351		360
Accrued expenses	167		201
Payables to affiliates	33		37



Customer deposits	60		55
Regulatory liabilities	12		17
Merger related obligation	20		22

Renewable energy credit obligations	134		169
Other	46		51
Total current liabilities	892		1,118
Long-term debt	4,626		4,356

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,581		1,509
Regulatory liabilities	276		310
Asset retirement obligations	48		49






Other	206		223
Total deferred credits and other liabilities	2,111		2,091
Total liabilities	7,629		7,565
Commitments and contingencies
Shareholder's equity
Common stock	3,527		3,335


Retained earnings	1,170		1,100

Total shareholder's equity	4,697		4,435
Total liabilities and shareholder's equity	$	12,326	$	12,000

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Potomac Electric Power Company

Statements Of Changes In Shareholder's Equity

(Unaudited)


	Nine Months Ended September 30, 2025
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2024	$	3,335	$	1,100	$	4,435
Net income	—		97		97
Common stock dividends	—		( 66 )		( 66 )
Contributions from parent	157		—		157
Balance at March 31, 2025	$	3,492	$	1,131	$	4,623
Net income	—		84		84



Common stock dividends	—		( 92 )		( 92 )
Contributions from parent	—		—		—
Balance at June 30, 2025	$	3,492	$	1,123	$	4,615
Net income	—		156		156



Common stock dividends	—		( 109 )		( 109 )
Contributions from parent	35		—		35
Balance at September 30, 2025	$	3,527	$	1,170	$	4,697


	Nine Months Ended September 30, 2024
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2023	$	3,075	$	1,069	$	4,144
Net income	—		75		75
Common stock dividends	—		( 51 )		( 51 )
Contributions from parent	251		—		251
Balance at March 31, 2024	$	3,326	$	1,093	$	4,419
Net income	—		108		108



Common stock dividends	—		( 102 )		( 102 )
Contributions from parent	—		—		—
Balance at June 30, 2024	$	3,326	$	1,099	$	4,425
Net income	—		140		140



Common stock dividends	—		( 133 )		( 133 )
Contributions from parent	9		—		9
Balance at September 30, 2024	$	3,335	$	1,106	$	4,441

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 September 30,				Nine Months Ended September 30,
(In millions)	2025		2024		2025		2024
Operating revenues
Electric operating revenues	$	467	$	440	$	1,316	$	1,215
Natural gas operating revenues	27		23		148		122
Revenues from alternative revenue programs	( 5 )		( 3 )		( 10 )		1
Operating revenues from affiliates	2		2		6		5
Total operating revenues	491		462		1,460		1,343
Operating expenses
Purchased power	211		196		580		529
Purchased fuel	8		7		57		44

Operating and maintenance	51		49		162		151
Operating and maintenance from affiliates	43		43		134		133
Depreciation and amortization	63		62		189		183
Taxes other than income taxes	21		20		63		59
Total operating expenses	397		377		1,185		1,099



Operating income	94		85		275		244
Other income and (deductions)
Interest expense, net	( 26 )		( 22 )		( 75 )		( 69 )

Other, net	4		6		12		20
Total other income and (deductions)	( 22 )		( 16 )		( 63 )		( 49 )
Income before income taxes	72		69		212		195
Income taxes	17		14		49		39

Net income	$	55	$	55	$	163	$	156
Comprehensive income	$	55	$	55	$	163	$	156

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Delmarva Power & Light Company

Statements Of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2025		2024
Cash flows from operating activities
Net income	$	163	$	156
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	189		183

Deferred income taxes and amortization of investment tax credits	24		12

Other non-cash operating activities	42		29
Changes in assets and liabilities:
Accounts receivable	20		( 1 )
Receivables from and payables to affiliates, net	( 3 )		( 3 )
Inventories	( 16 )		( 17 )
Accounts payable and accrued expenses	15		14
Collateral received, net	—		2
Income taxes	( 1 )		( 25 )
Regulatory assets and liabilities, net	( 32 )		( 41 )
Pension and non-pension postretirement benefit contributions	( 1 )		( 1 )
Other assets and liabilities	23		19
Net cash flows provided by operating activities	423		327
Cash flows from investing activities
Capital expenditures	( 402 )		( 404 )




Net cash flows used in investing activities	( 402 )		( 404 )
Cash flows from financing activities
Changes in short-term borrowings	( 111 )		( 63 )
Issuance of long-term debt	125		175
Retirement of long-term debt	—		( 33 )

Dividends paid on common stock	( 149 )		( 162 )
Contributions from parent	107		160
Other financing activities	( 8 )		( 6 )
Net cash flows (used in) provided by financing activities	( 36 )		71
Decrease in cash, restricted cash, and cash equivalents	( 15 )		( 6 )
Cash, restricted cash, and cash equivalents at beginning of period	23		16
Cash, restricted cash, and cash equivalents at end of period	$	8	$	10

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	( 40 )	$	9

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Delmarva Power & Light Company

Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
ASSETS
Current assets
Cash and cash equivalents	$	6	$	21
Restricted cash and cash equivalents	2		2
Accounts receivable
Customer accounts receivable	178		210
Customer allowance for credit losses	( 20 )		( 17 )
Customer accounts receivable, net	158		193
Other accounts receivable	67		63
Other allowance for credit losses	( 9 )		( 9 )
Other accounts receivable, net	58		54
Receivables from affiliates	1		—

Inventories, net
Fossil fuel	9		6
Materials and supplies	108		95
Prepaid utility taxes	—		26

Regulatory assets	69		60
Prepaid renewable energy credits	22		29
Other	10		16
Total current assets	443		502
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 2,196 and $ 2,075 as of September 30, 2025 and December 31, 2024, respectively)	5,733		5,540
Deferred debits and other assets
Regulatory assets	212		215


Prepaid pension asset	107		120
Other	45		44
Total deferred debits and other assets	364		379
Total assets	$	6,540	$	6,421

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Delmarva Power & Light Company

Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	33	$	144
Long-term debt due within one year	53		130
Accounts payable	147		187
Accrued expenses	71		55
Payables to affiliates	23		26

Customer deposits	35		34
Regulatory liabilities	38		42
Renewable energy credit obligations	35		48
Other	18		22
Total current liabilities	453		688
Long-term debt	2,291		2,090
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	983		946
Regulatory liabilities	316		325
Asset retirement obligations	12		13

Non-pension postretirement benefit obligations	2		3
Other	120		114
Total deferred credits and other liabilities	1,433		1,401
Total liabilities	4,177		4,179
Commitments and contingencies
Shareholder's equity
Common stock	1,722		1,615

Retained earnings	641		627
Total shareholder's equity	2,363		2,242
Total liabilities and shareholder's equity	$	6,540	$	6,421

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Delmarva Power & Light Company

Statements Of Changes In Shareholder's Equity

(Unaudited)


	Nine Months Ended September 30, 2025
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2024	$	1,615	$	627	$	2,242
Net income	—		69		69
Common stock dividends	—		( 46 )		( 46 )
Contributions from parent	99		—		99
Balance at March 31, 2025	$	1,714	$	650	$	2,364
Net income	—		39		39
Common stock dividends	—		( 44 )		( 44 )
Contributions from parent	—		—		—
Balance at June 30, 2025	$	1,714	$	645	$	2,359
Net income	—		55		55
Common stock dividends	—		( 59 )		( 59 )
Contributions from parent	8		—		8
Balance at September 30, 2025	$	1,722	$	641	$	2,363


	Nine Months Ended September 30, 2024
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2023	$	1,455	$	638	$	2,093
Net income	—		66		66
Common stock dividends	—		( 45 )		( 45 )
Contributions from parent	154		—		154
Balance at March 31, 2024	$	1,609	$	659	$	2,268
Net income	—		34		34
Common stock dividends	—		( 39 )		( 39 )

Balance at June 30, 2024	$	1,609	$	654	$	2,263
Net income	—		55		55
Common stock dividends	—		( 78 )		( 78 )
Contributions from parent	6		—		6
Balance at September 30, 2024	$	1,615	$	631	$	2,246

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 September 30,				Nine Months Ended September 30,
(In millions)	2025		2024		2025		2024
Operating revenues
Electric operating revenues	$	553	$	533	$	1,323	$	1,281
Revenues from alternative revenue programs	16		6		2		( 3 )
Operating revenues from affiliates	1		1		3		2
Total operating revenues	570		540		1,328		1,280
Operating expenses
Purchased power	286		245		616		557

Operating and maintenance	55		58		161		155
Operating and maintenance from affiliates	37		38		116		119
Depreciation and amortization	61		67		188		214
Taxes other than income taxes	2		2		7		7
Total operating expenses	441		410		1,088		1,052



Operating income	129		130		240		228
Other income and (deductions)
Interest expense, net	( 20 )		( 21 )		( 62 )		( 59 )

Other, net	2		4		8		12
Total other income and (deductions)	( 18 )		( 17 )		( 54 )		( 47 )
Income before income taxes	111		113		186		181
Income taxes	29		30		48		48

Net income	$	82	$	83	$	138	$	133
Comprehensive income	$	82	$	83	$	138	$	133

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Atlantic City Electric Company and Subsidiary Company

Statements Of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2025		2024
Cash flows from operating activities
Net income	$	138	$	133
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	188		214
Deferred income taxes and amortization of investment tax credits	32		33
Other non-cash operating activities	42		49
Changes in assets and liabilities:
Accounts receivable	9		( 77 )
Receivables from and payables to affiliates, net	( 8 )		( 8 )
Inventories	( 10 )		( 5 )
Accounts payable and accrued expenses	5		( 18 )

Income taxes	3		( 2 )
Regulatory assets and liabilities, net	( 14 )		( 62 )
Pension and non-pension postretirement benefit contributions	( 3 )		( 7 )
Other assets and liabilities	( 21 )		( 39 )
Net cash flows provided by operating activities	361		211
Cash flows from investing activities
Capital expenditures	( 292 )		( 265 )



Net cash flows used in investing activities	( 292 )		( 265 )
Cash flows from financing activities
Changes in short-term borrowings	( 116 )		( 30 )


Issuance of long-term debt	100		250
Retirement of long-term debt	—		( 150 )

Dividends paid on common stock	( 132 )		( 100 )
Contributions from parent	98		85
Other financing activities	( 5 )		( 5 )
Net cash flows (used in) provided by financing activities	( 55 )		50
Increase (decrease) in cash and cash equivalents	14		( 4 )
Cash and cash equivalents at beginning of period	14		21
Cash and cash equivalents at end of period	$	28	$	17

Supplemental cash flow information
Decrease in capital expenditures not paid	$	( 19 )	$	( 10 )

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Atlantic City Electric Company and Subsidiary Company

Consolidated Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
ASSETS
Current assets
Cash and cash equivalents	$	25	$	14
Restricted cash and cash equivalents	3		—
Accounts receivable
Customer accounts receivable	221		223
Customer allowance for credit losses	( 31 )		( 32 )
Customer accounts receivable, net	190		191
Other accounts receivable	64		79
Other allowance for credit losses	( 14 )		( 13 )
Other accounts receivable, net	50		66

Receivables from affiliates	11		7

Inventories, net	72		62


Prepaid utility taxes	7		—
Regulatory assets	94		101
Other	8		6
Total current assets	460		447
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 1,917 and $ 1,798 as of September 30, 2025 and December 31, 2024, respectively)	4,484		4,366
Deferred debits and other assets
Regulatory assets	526		502



Prepaid pension asset	3		1

Other	43		33
Total deferred debits and other assets	572		536
Total assets	$	5,516	$	5,349

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Atlantic City Electric Company and Subsidiary Company

Consolidated Balance Sheets

(Unaudited)


(In millions)	September 30, 2025		December 31, 2024
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	70	$	186
Long-term debt due within one year	155		154
Accounts payable	164		163
Accrued expenses	47		52
Payables to affiliates	18		22



Customer deposits	25		24
Regulatory liabilities	66		10

Other	10		10
Total current liabilities	555		621
Long-term debt	1,880		1,779
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	851		816
Regulatory liabilities	138		146






Other	64		62
Total deferred credits and other liabilities	1,053		1,024
Total liabilities	3,488		3,424
Commitments and contingencies
Shareholder's equity
Common stock	2,013		1,915
Retained earnings	15		10

Total shareholder's equity	2,028		1,925
Total liabilities and shareholder's equity	$	5,516	$	5,349

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)


	Nine Months Ended September 30, 2025
(In millions)	Common Stock		Retained (Deficit) Earnings		Total Shareholder's Equity
Balance at December 31, 2024	$	1,915	$	10	$	1,925
Net income	—		31		31
Common stock dividends	—		( 20 )		( 20 )
Contributions from parent	94		—		94
Balance at March 31, 2025	$	2,009	$	21	$	2,030
Net income	—		24		24
Common stock dividends	—		( 24 )		( 24 )
Contributions from parent	—		—		—
Balance at June 30, 2025	$	2,009	$	21	$	2,030
Net income	—		82		82
Common stock dividends	—		( 88 )		( 88 )
Contributions from parent	4		—		4
Balance at September 30, 2025	$	2,013	$	15	$	2,028


	Nine Months Ended September 30, 2024
(In millions)	Common Stock		Retained (Deficit) Earnings		Total Shareholder's Equity
Balance at December 31, 2023	$	1,830	$	( 18 )	$	1,812
Net income	—		29		29
Common stock dividends	—		( 22 )		( 22 )
Contributions from parent	81		—		81
Balance at March 31, 2024	$	1,911	$	( 11 )	$	1,900
Net income	—		21		21
Common stock dividends	—		( 22 )		( 22 )

Balance at June 30, 2024	$	1,911	$	( 12 )	$	1,899
Net income	—		83		83
Common stock dividends	—		( 56 )		( 56 )
Contributions from parent	4		—		4
Balance at September 30, 2024	$	1,915	$	15	$	1,930

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Combined Notes to Consolidated Financial Statements

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

Note 1 — Significant Accounting Policies

1. Significant Accounting Policies (All Registrants)

Description of Business (All Registrants)

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

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 (All Registrants)

This is a combined quarterly report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrants' Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

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

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 September 30, 2025 and for the three and nine months ended September 30, 2025 and 2024 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, 2024 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, 2025. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.

New Accounting Standards (All Registrants)

New Accounting Standards Issued and Not Yet Adopted as of September 30, 2025: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of September 30, 2025. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation that such standards will not significantly impact the Registrants' financial reporting.

Improvement to Income Tax Disclosures (Issued December 2023). Provides additional disclosure requirements related to the effective tax rate reconciliation and income taxes paid. Under the revised guidance for the effective tax reconciliations, entities would be required to disclose: (1) eight specific categories in the effective tax rate reconciliation in both percentages and reporting currency amount, (2) additional information for reconciling items over a certain threshold, (3) explanation of individual reconciling items disclosed, and (4) provide a qualitative description of the state and local jurisdictions that contribute to the majority of the state income tax expense. For each annual period presented, the new standard requires disclosure of the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign. It also requires additional disaggregated information on income taxes paid (net of refunds received) to an individual jurisdiction equal to or greater than 5% of total income taxes paid (net of refunds received). The standard is effective for annual periods beginning January 1, 2025.

Disaggregation of Income Statement Expenses (Issued November 2024) . Provides additional disclosure requirements related to relevant expense captions of income statement expense line items. The revised guidance requires a new tabular disclosure of disaggregated income statement expenses including a break out of (1) purchases of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, (5) depreciation, depletion, and amortization recognized as part of oil and gas producing activities included in each relevant expense line item on the income statement. The tabular disaggregation should include certain amounts already required to be disclosed under GAAP elsewhere. Any remaining amounts not separately disaggregated quantitatively should include a qualitative description. Additionally, on an annual basis, the standard requires disclosure of management’s definition of selling expenses and the amount of expense. The standard is effective January 1, 2027, with early adoption permitted.

2. Regulatory Matters (All Registrants)

As discussed in Note 3 — Regulatory Matters of the 2024 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2025 and updates to the 2024 Form 10-K.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2025.

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	January 17, 2023 (a)	Electric	$	1,487	$	1,045	8.905 %	December 19, 2024	January 1, 2024
	April 26, 2024 (amended on September 11, 2024) (b)	Electric	$	624	$	623	9.89 %	October 31, 2024	January 1, 2025
PECO - Pennsylvania	March 28, 2024	Electric (c)(d)	$	464	$	354	N/A (e)	December 12, 2024	January 1, 2025
		Natural Gas (d)	$	111	$	78
BGE - Maryland (f)	February 17, 2023	Electric	$	313	$	179	9.50 %	December 14, 2023	January 1, 2024
		Natural Gas	$	289	$	229	9.45 %
Pepco - District of Columbia (g)	April 13, 2023 (amended February 27, 2024)	Electric	$	186	$	123	9.50 %	November 26, 2024	January 1, 2025
Pepco - Maryland (h)	May 16, 2023 (amended February 23, 2024)	Electric	$	111	$	45	9.50 %	June 10, 2024	April 1, 2024
DPL - Maryland (i)	May 19, 2022	Electric	$	38	$	29	9.60 %	December 14, 2022	January 1, 2023
DPL - Delaware (j)	December 15, 2022 (amended September 29, 2023)	Electric	$	39	$	28	9.60 %	April 18, 2024	July 15, 2023
ACE - New Jersey (k)	February 15, 2023 (amended August 21, 2023)	Electric	$	92	$	45	9.60 %	November 17, 2023	December 1, 2023

__________

(a) Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. The MRP was originally approved by the ICC on December 14, 2023 and was subsequently amended on January 10, 2024, April 18, 2024 and December 19, 2024. The December 19, 2024 order provided a total revenue requirement increase of $ 1.045 billion inclusive of rate increases of approximately $ 752 million in 2024, $ 80 million in 2025, $ 102 million in 2026, and $ 111 million in 2027. On March 20, 2025, ComEd filed its annual revenue balancing reconciliation for 2024. This reconciliation, which is a component of revenue decoupling, reflected a revenue reduction of $ 55 million, effective January 1, 2026. On April 29, 2025, ComEd filed its 2024 MRP Reconciliation reflecting a revenue increase of $ 268 million, which includes the tax benefit of NOLCs. While NOLCs were included in the MRP Reconciliation, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 6 — Income Taxes for additional information on NOLCs.

(b) On October 31, 2024, the Delivery Reconciliation Amount for 2023 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. Rider DSPR 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 2024 order reconciled the delivery service rates in effect in 2023 with the actual delivery service costs incurred in 2023. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 7.02 %, inclusive of an allowed ROE of 9.89 %, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

(c) PECO’s approved annual electric revenue requirement increase of $ 354 million is partially offset by a one-time credit of $ 64 million in 2025. In addition, the PAPUC approved the recovery of storm damage costs incurred by PECO in January 2024, up to $ 23 million, subject to review for reasonableness and prudency in PECO’s next distribution rate case.

(d) On December 12, 2024, the PAPUC issued their Opinions and Orders which approved the non-unanimous partial settlements with limited modifications for both the electric and natural gas base rate cases, and denied the Weather Normalization Adjustment requested in the natural gas base rate case.

(e) The PECO electric and natural gas base rate case proceedings were resolved through settlement agreements, which did not specify an approved ROE.

(f) Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $ 41 million, $ 113 million, and $ 25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $ 126 million, $ 62 million, and $ 41 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 MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which was recovered through separate electric and gas riders between March 2024 through February 2025. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $ 13 million and $ 7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $ 39 million and $ 15 million for electric and gas, respectively. In April 2024, BGE filed with the MDPSC its request for recovery of the 2023 reconciliation amounts of $ 79 million and $ 73 million for electric and gas, respectively, with supporting testimony and schedules.

(g) Reflects a two-year cumulative multi-year plan for January 1, 2025, through December 31, 2026. The DCPSC awarded Pepco electric incremental revenue requirement increases of $ 99 million and $ 24 million for 2025 and 2026, respectively.

(h) Reflects the amounts requested (before offsets) and awarded for a one-year multi-year plan for April 1, 2024 through March 31, 2025. The MDPSC awarded Pepco an electric incremental revenue requirement increase of $ 45 million for the 12-month period ending March 31, 2025. The MDPSC did not adopt the requested revenue requirement increases of $ 80 million (before offsets), $ 51 million, and $ 14 million as filed for 2025, 2026, and the 2027 nine-month extension period, respectively. The MDPSC also approved the requested reconciliation amounts for the 12-month periods ending March 31, 2022, and March 31, 2023, which will be recovered through a rider between August 2024 through March 2026. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The reconciliation amounts are $ 1 million and $ 7 million, for the 12-month periods ending March 31, 2022, and March 31, 2023, respectively. In July 2024, Pepco filed its request with the MDPSC for recovery of $ 31 million for the 12-month period ended March 31, 2024, with supporting testimony and schedules.

(i) 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.

(j) On April 18, 2024, the DEPSC approved the Significant Storm Expense Rate Rider (Rider SSER) which will allow DPL to recover expenses associated with qualified storms. A qualified storm will be an individual storm for which DPL incurs expenses between $ 5 million and $ 15 million. The Rider SSER allows DPL to recover significant storm damage expenses for the previous 12-month period over a future 24-month period. For individual storm events for which DPL incurs expenses of more than $ 15 million, the future recovery period will be evaluated on a case-by-case basis and the unamortized balance will earn a return at DPL's authorized long-term cost of debt. The Rider SSER will have an annual true-up filing, subject to DEPSC review and approval.

(k) Requested and approved increases are before New Jersey sales and use tax. The NJBPU awarded ACE electric revenue requirement increases of $ 36 million and $ 9 million effective December 1, 2023 and February 1, 2024, respectively.

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

Pepco - Maryland

October 14, 2025

Electric

133

10.50 %

Third quarter of 2026

DPL - Delaware (a)

September 20, 2024 (amended September 5, 2025)

Natural Gas

10.65 %

First quarter of 2026

ACE - New Jersey (b)

November 21, 2024

Electric

109

10.70 %

Fourth quarter of 2025

__________

(a) DPL implemented interim rates on April 20, 2025, subject to refund.

(b) Requested increases are before New Jersey sales and use tax. ACE may implement interim rates, subject to refund.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

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 2025, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:


Registrant (a)	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation Increase (Decrease)		Total Revenue Requirement Increase (Decrease) (b)			Allowed Return on Rate Base (c)		Allowed ROE (d)
ComEd	$	78	$	49	$	127		8.13	%	11.50	%
PECO	$	9	$	13	$	22		7.54	%	10.35	%
BGE	$	21	$	21	$	35	(e)	7.53	%	10.50	%
Pepco	$	35	$	16	$	51		7.71	%	10.50	%
DPL	$	32	$	( 9 )	$	23		7.48	%	10.50	%
ACE	$	( 11 )	$	( 46 )	$	( 57 )		7.16	%	10.50	%

__________

(a) All rates are effective June 1, 2025 - May 31, 2026, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariffs.

(b) For the Utility Registrants, except for PECO, while the transmission filing reflects the tax benefit of NOLCs, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 6 — Income Taxes for additional information on NOLCs.

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

(e) The increase in BGE's transmission revenue requirement includes a $ 7 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) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics.

ComEd Electric Distribution Rates

Beginning in 2024, ComEd recovers 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

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

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.

On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s Grid Plan as non-compliant with certain requirements of CEJA and required ComEd to file a revised Grid Plan. In the absence of an approved Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This resulted in a total cumulative revenue requirement increase of $ 501 million, a $ 986 million total revenue reduction from the requested cumulative revenue requirement increase but remained subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC's December 2023 order also denied ComEd's ability to earn a return on its pension asset.

On December 22, 2023, ComEd filed an application for rehearing on several findings in the final order including the use of the 2022 year-end rate base to establish forecast revenue requirements for 2024-2027, ROE, pension asset return, and capital structure. On January 10, 2024, ComEd’s application for rehearing was denied on all issues except for the order’s use of the 2022 year-end rate base. On April 18, 2024, the ICC issued its final order on rehearing, which approved the use of the forecasted year-end 2023 rate base that resulted in increased revenue requirements for 2024-2027. These revenue requirements determined during the rehearing process established base revenue requirements until the ICC approved the Refiled Grid Plan on December 19, 2024.

On January 10, 2024, ComEd filed an appeal in the Illinois Appellate Court of the issues on which rehearing was denied, including but not limited to the allowed ROE, 50 % equity ratio, and denial of a return on ComEd’s pension asset. There is no deadline by when the appellate court must rule. On March 13, 2024, ComEd filed its Refiled Grid Plan with supporting testimony and schedules with the ICC and subsequently on March 15, 2024, ComEd also filed a petition to adjust its MRP to authorize increased rates consistent with the Refiled Grid Plan. On December 19, 2024, the ICC approved the Refiled Grid Plan and adjusted the approved MRP with rates effective on January 1, 2025. The final approved MRP, as adjusted, which reflects the Refiled Grid Plan, resulted in a total cumulative revenue requirement increase of $ 1.045 billion over the 2024-2027 plan years and remains subject to annual reconciliations in accordance with CEJA. ComEd filed timely requests for rehearing and an appeal of the MRP order, again limited to the issues on which rehearing of the December 2023 order was denied, including the allowed ROE, 50 % equity ratio, and denial of a return on ComEd's pension asset.

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, 2023, 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.

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 power 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 credit or other subsidy if applicable. As of September 30, 2025, the seller had not provided notification to ComEd or the IPA that any subsidies or tax credits, such as nuclear production tax credits that became available for electricity generated beginning January 1, 2024, have been monetized and the IPA has not adjusted the CMC price paid by ComEd. 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. Beginning with the June 2022 monthly billing period, ComEd began issuing credits and/or charges to its retail customers under its CMC rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). A regulatory asset is recorded for the difference between ComEd's costs associated with the procurement of CMCs from

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

participating nuclear power generating facilities and revenues received from customers. The balance as of September 30, 2025 is $ 94 million. On October 31, 2025, the seller provided notification to ComEd and the IPA that it has reflected on its 2024 federal income tax return $ 804 million of nuclear production tax credits associated with its participating nuclear power generating facilities. These amounts will be collected from the seller and returned to customers. In the fourth quarter of 2025, Exelon and ComEd’s Consolidated Balance Sheets will reflect these amounts as a receivable from the seller with an offsetting regulatory liability.

On February 2, 2024, ComEd filed a petition with the ICC to initiate the reconciliation proceeding for the costs incurred in connection with the procurement of CMC’s during the delivery year beginning June 1, 2022 and extending through May 31, 2023. While both Staff and the Administrative Law Judge's proposed order supported ComEd’s proposed reconciliation adjustment, on September 4, 2025, the ICC issued its final order rejecting the proposed reconciliation adjustment. Specifically, the order disallowed portions of the administrative costs as well as a portion of ComEd's interest costs on the balance of credit extended to customers under the applicable tariff that were not yet funded by payments from the generator. The CMC costs themselves were not disallowed. The order resulted in an immaterial impact to the financial statements and on October 3, 2025 ComEd filed its Application for Rehearing. On October 16, 2025, the ICC denied ComEd's Application. On October 17, 2025, ComEd filed its appeal with the Illinois Appellate Court for review of the ICC's order and its denial of rehearing.

Energy Efficiency

CEJA extends ComEd’s current cumulative annual energy efficiency MWh savings goals through 2040, adds expanded electrification measures to those goals, increases low-income commitments, and adds a new performance adjustment to the energy efficiency formula rate. ComEd expects its annual spend to increase through 2040 to achieve these energy efficiency MWh savings goals, which is deferred as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.

Energy Efficiency Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on May 23, 2025. The revenue requirement is used to set the rates that will take effect in January 2026, subject to the ICC's review and approval. The requested revenue requirement update is based on a reconciliation of the 2024 actual costs plus projected 2026 expenditures.


Initial Revenue Requirement Increase		Annual Reconciliation Decrease		Total Revenue Requirement Increase		Requested Return on Rate Base (a)		Requested ROE
$	24	$	( 4 )	$	20	7.24	%	10.21	%

__________

(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 7.24 % inclusive of an allowed ROE of 10.21 %, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 2024 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 7.51 % inclusive of an allowed ROE of 10.75 %, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals.

Maryland Regulatory Matters

Next Generation Energy Act (Exelon, BGE, PHI, Pepco, and DPL). On May 20, 2025, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including affirming that the MDPSC may approve the use of multi-year rate plans that demonstrate customer benefits, among other things. It also prohibits utilities from filing after January 1, 2025, for the reconciliation of actuals costs and revenues to amounts approved within the multi-year plans. In the second quarter of 2025, BGE derecognized Regulatory assets of $ 10 million and Regulatory liabilities of $ 3 million for multi-year plan reconciliations that will no longer be filed. DPL also derecognized Regulatory liabilities of $ 0.4 million during the second quarter of 2025 for multi-year reconciliations yet to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings.

Summer Rate Mitigation (Exelon, BGE, PHI, Pepco, and DPL). As part of the passing of the Next Generation Energy Act by the Maryland General Assembly, the MDPSC issued an order on June 26, 2025, to implement the Legislative Energy Relief Refund program under which bill credits will be distributed to residential customers

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

based on their consumption of electricity supply that is subject to the renewable energy portfolio standard. On July 24, 2025, the MDPSC issued an order accepting BGE, Pepco, and DPL's proposal for the implementation of the program. As a result, BGE, Pepco, and DPL received $ 49 million, $ 21 million, and $ 8 million, respectively, from the MDPSC on August 6, 2025. These amounts were used to reduce residential customer account receivable balances within the third quarter of 2025. An additional disbursement from the state of Maryland is expected in the first quarter of 2026, which will also be used to reduce residential customer receivables upon receipt.

New Jersey Regulatory Matters

Summer Rate Mitigation (Exelon and ACE). In response to significant increases in electric supply costs, on April 23, 2025, the NJBPU issued an order directing the State's electric public utilities to file petitions proposing distribution side measures to mitigate residential customer bill impacts during summer months. As a result, on June 18, 2025, the NJBPU approved a stipulation of settlement for ACE to issue a bill credit of $ 30 per residential customer for the months of July and August 2025, which was deferred to a Regulatory asset. The amounts will subsequently be collected from September 2025 through February 2026 at a flat rate of $ 10 per residential customer. The bill credit and subsequent collections will not be subject to carrying costs.

Residential Universal Bill Credit (Exelon and ACE). In an effort to further reduce the burden of increased electric supply costs, on August 13, 2025, the NJBPU issued an order to establish the RUBC, which will be funded by the NJBPU. The program will provide a $ 50 bill credit per eligible residential customer for the months of September and October 2025. ACE received $ 51 million from the NJBPU on September 25, 2025, which was recognized as a Regulatory liability. ACE subsequently issued $ 25 million in bill credits to residential customers in September 2025 reducing the Regulatory liability to $ 26 million as of September 30, 2025. The remaining funds were disbursed in October 2025.

Other Federal Regulatory Matters

FERC Audit (Exelon and ComEd). The Utility Registrants are subject to periodic audits and investigations 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 period extended back to January 1, 2017.

On July 27, 2023, FERC published 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, including a suggestion that refunds may be due to customers for amounts collected in previous years. ComEd responded to that report and on August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place.

On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $ 70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The existing loss estimate was reflected in Exelon and ComEd's financial statements as of December 31, 2024. ComEd and FERC staff jointly filed the settlement agreement with FERC for approval on February 11, 2025. The settlement was approved by FERC on April 4, 2025.

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2024, unless noted below. See Note 3 — Regulatory Matters of the 2024 Form 10-K for additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets decreased $ 370 million primarily due to a decrease of $ 453 million in the Electric distribution formula rate annual reconciliations, partially offset by an increase of $ 73 million in the Zero emission credit regulatory assets. Regulatory liabilities increased $ 644 million primarily due to an increase of $ 451 million in the Decommissioning the Regulatory Agreement Units and an increase of $ 193 million in Renewable portfolio standards costs regulatory liabilities.

PECO. Regulatory assets increased $ 229 million primarily due to an increase of $ 184 million in the Deferred income taxes regulatory asset and an increase of $ 53 million in the Deferred storm cost regulatory asset. Regulatory liabilities increased $ 212 million primarily due to an increase of $ 181 million in the Decommissioning the Regulatory Agreement Units and an increase of $ 44 million in the Electric energy and natural gas costs regulatory liabilities.

BGE. Regulatory liabilities decreased $ 28 million primarily due to a decrease of $ 41 million in the Deferred income taxes regulatory liability, partially offset by an increase of $ 10 million in the Transmission formula rate annual reconciliations regulatory liability.

Pepco. Regulatory liabilities decreased $ 39 million primarily due to a decrease of $ 37 million in the Deferred income taxes regulatory liability.

DPL. Regulatory assets increased $ 6 million primarily due to an increase of $ 16 million in the Electric energy and natural gas costs regulatory asset, partially offset by a decrease of $ 8 million in the Transmission formula rate annual reconciliations regulatory asset.

ACE. Regulatory assets increased $ 17 million primarily due to an increase of $ 26 million in the Summer rate mitigation regulatory asset. Regulatory liabilities increased $ 48 million primarily due to an increase of $ 26 million in the RUBC regulatory liability, an increase of $ 12 million in the Transmission formula rate annual reconciliations regulatory liability, and an increase of $ 6 million in the Electric energy and natural gas costs regulatory liability.

Capitalized Ratemaking Amounts Not Recognized

The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders' investment that are not recognized for financial reporting purposes in 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 September 30, 2025 and December 31, 2024.


	Exelon		ComEd (a)		BGE (b)		PHI		Pepco (c)		DPL (d)		ACE (e)
September 30, 2025	$	67	$	21	$	5	$	41	$	23	$	1	$	17

December 31, 2024	117		46		16		55		40		1		14

__________

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

(b) BGE's amount capitalized for ratemaking purposes primarily relates to earnings on shareholders' investment on AMI programs and investments in rate base included in the multi-year plan reconciliations.

(c) Pepco's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs, Energy efficiency and demand response programs, investments in rate base and revenues included in the multi-year plan reconciliations, and a portion of Pepco District of Columbia's revenue decoupling.

(d) DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on AMI programs and Energy efficiency and demand response programs.

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

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 3 — Revenue from Contracts with Customers

3. Revenue from Contracts with Customers (All Registrants)

The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. 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 2024 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 Pepco, DPL, and ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement ("Agreement") with an unrelated owner and manager of communication infrastructure, as well as additional consideration received for the payment option amendment ("Amendment") executed during the fourth quarter of 2023, which is discussed in further detail within Note 4 — Revenue from Contracts with Customers of the 2024 Form 10-K. The contract liability balance attributable to the Agreement and the Amendment is being recognized as Electric operating revenues over a 35 year period and 31 year period, respectively.

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 nine months ended September 30, 2025 and 2024. At September 30, 2025 and December 31, 2024, ComEd's, PECO's, and BGE's contract liabilities were immaterial.



	Exelon (a)		PHI (a)		Pepco (a)		DPL		ACE
Balance at December 31, 2024	$	127	$	127	$	101	$	13	$	13
Revenues recognized	( 1 )		( 1 )		( 1 )		—		—
Balance at March 31, 2025	$	126	$	126	$	100	$	13	$	13
Revenues recognized	( 3 )		( 3 )		( 2 )		( 1 )		—
Balance at June 30, 2025	$	123	$	123	$	98	$	12	$	13
Revenues recognized	( 1 )		( 1 )		( 1 )		—		—
Balance at September 30, 2025	$	122	$	122	$	97	$	12	$	13

	Exelon (a)		PHI (a)		Pepco (a)		DPL		ACE
Balance at December 31, 2023	$	133	$	133	$	107	$	13	$	13
Revenues recognized	( 2 )		( 2 )		( 2 )		—		—
Balance at March 31, 2024	$	131	$	131	$	105	$	13	$	13
Revenues recognized	( 1 )		( 1 )		( 1 )		—		—
Balance at June 30, 2024	$	130	$	130	$	104	$	13	$	13
Revenues recognized	( 2 )		( 2 )		( 2 )		—		—
Balance at September 30, 2024	$	128	$	128	$	102	$	13	$	13

__________

(a) Revenues recognized in the three and nine months ended September 30, 2025 and 2024, were included in the contract liabilities at December 31, 2024 and 2023, 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 September 30, 2025. 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.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 3 — Revenue from Contracts with Customers

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
2025	$	3	$	3	$	2	$	—	$	1
2026	5		5		5		—		—
2027	6		6		5		1		—
2028	6		6		5		—		1
2029 and thereafter	102		102		80		11		11
Total	$	122	$	122	$	97	$	12	$	13

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 4 — Segment Information for the presentation of the Registrants' revenue disaggregation.

4. 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. The Chief Executive Officer is the CODM for Exelon. For PHI and each of the Utility Registrants, CODM responsibilities are shared by Exelon's Chief Operating Officer and the Utility Registrant's Chief Executive Officer.

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, PHI, Pepco, DPL, and ACE's CODMs rely on a variety of business considerations, including net income, in evaluating segment performance, determining reinvestment of profits, and establishing the amounts of dividend distributions.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2025 and 2024 is as follows:

Three Months Ended September 30, 2025 and 2024



	ComEd		PECO		BGE		PHI		Other (a)		Intersegment Eliminations		Exelon
Operating revenues (b) :
2025
Electric revenues	$	2,275	$	1,097	$	1,091	$	2,021	$	—	$	( 6 )	$	6,478
Natural gas revenues	—		83		118		27		—		( 1 )		227
Shared service and other revenues	—		—		—		3		447		( 450 )		—
Total operating revenues	$	2,275	$	1,180	$	1,209	$	2,051	$	447	$	( 457 )	$	6,705
2024
Electric revenues	$	2,229	$	960	$	925	$	1,836	$	—	$	( 6 )	$	5,944
Natural gas revenues	—		70		119		23		—		( 2 )		210
Shared service and other revenues	—		—		—		3		441		( 444 )		—
Total operating revenues	$	2,229	$	1,030	$	1,044	$	1,862	$	441	$	( 452 )	$	6,154
Less:
Purchased power
2025	$	806	$	428	$	547	$	864	$	—	$	—	$	2,645

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information


2024	835		372		407		735		—		—		2,349
Purchased fuel
2025	$	—	$	18	$	21	$	8	$	—	$	—	$	47
2024	—		14		13		7		—		—		34



Operating and maintenance
2025	$	313	$	183	$	179	$	290	$	409	$	( 202 )	$	1,172
2024	307		251		221		275		404		( 183 )		1,275
Operating and maintenance from affiliates
2025	$	96	$	58	$	60	$	45	$	11	$	( 270 )	$	—
2024	103		62		60		47		11		( 283 )		—
Depreciation and amortization
2025	$	395	$	115	$	155	$	234	$	13	$	—	$	912
2024	387		108		162		235		16		—		908
Taxes other than income taxes
2025	$	107	$	69	$	93	$	150	$	10	$	—	$	429
2024	99		61		86		140		9		—		395
(Gain) on sale of assets
2025	$	—	$	—	$	—	$	—	$	—	$	—	$	—
2024	—		—		—		—		( 3 )		—		( 3 )
Interest expense, net (c)
2025	$	132	$	63	$	64	$	102	$	170	$	—	$	531
2024	125		55		57		95		158		—		490
Interest expense to affiliates, net (c)
2025	$	3	$	2	$	—	$	—	$	—	$	2	$	7
2024	3		3		—		—		—		—		6
Other, net
2025	$	( 33 )	$	( 11 )	$	( 15 )	$	( 18 )	$	( 4 )	$	13	$	( 68 )
2024	( 26 )		( 9 )		( 11 )		( 22 )		( 3 )		14		( 57 )
Income Taxes
2025	$	83	$	5	$	23	$	85	$	( 41 )	$	—	$	155
2024	36		( 4 )		4		72		( 58 )		—		50
Net income (loss) attributable to common shareholders
2025	$	373	$	250	$	82	$	291	$	( 121 )	$	—	$	875
2024	360		117		45		278		( 93 )		—		707
Supplemental segment information
Intersegment revenues (d)
2025	$	2	$	3	$	2	$	2	$	444	$	( 453 )	$	—
2024	2		4		3		3		438		( 450 )		—
Capital Expenditures
2025	$	781	$	502	$	407	$	444	$	2	$	—	$	2,136
2024	508		382		365		440		—		—		1,695

__________

(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 Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.

(c) Interest expense, net and Interest expense to affiliates, net are primarily inclusive of Interest expense, which is partially offset by an immaterial amount of Interest income.

(d) See Note 15 — Related Party Transactions for additional information on intersegment revenues.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information

PHI:



	Pepco		DPL		ACE		Other (a)		Intersegment Eliminations		PHI
Operating revenues (b) :
2025
Electric revenues	$	992	$	464	$	570	$	—	$	( 5 )	$	2,021
Natural gas revenues	—		27		—		—		—		27
Shared service and other revenues	—		—		—		106		( 103 )		3
Total operating revenues	$	992	$	491	$	570	$	106	$	( 108 )	$	2,051
2024
Electric revenues	$	861	$	439	$	540	$	—	$	( 4 )	$	1,836
Natural gas revenues	—		23		—		—		—		23
Shared service and other revenues	—		—		—		103		( 100 )		3
Total operating revenues	$	861	$	462	$	540	$	103	$	( 104 )	$	1,862
Less:
Purchased power
2025	$	367	$	211	$	286	$	—	$	—	$	864
2024	294		196		245		—		—		735
Purchased fuel
2025	$	—	$	8	$	—	$	—	$	—	$	8
2024	—		7		—		—		—		7



Operating and maintenance
2025	$	95	$	51	$	55	$	89	$	—	$	290
2024	82		49		58		86		—		275
Operating and maintenance from affiliates
2025	$	59	$	43	$	37	$	14	$	( 108 )	$	45
2024	58		43		38		12		( 104 )		47
Depreciation and amortization
2025	$	110	$	63	$	61	$	—	$	—	$	234
2024	102		62		67		4		—		235
Taxes other than income taxes
2025	$	122	$	21	$	2	$	5	$	—	$	150
2024	114		20		2		4		—		140
Loss on sale of assets
2025	$	—	$	—	$	—	$	—	$	—	$	—
2024	—		—		—		—		—		—
Interest expense, net (c)
2025	$	53	$	26	$	20	$	3	$	—	$	102
2024	50		22		21		2		—		95
Interest expense to affiliates, net (c)
2025	$	—	$	—	$	—	$	—	$	—	$	—
2024	—		—		—		1		( 1 )		—
Other, net
2025	$	( 11 )	$	( 4 )	$	( 2 )	$	( 1 )	$	—	$	( 18 )
2024	( 11 )		( 6 )		( 4 )		( 2 )		1		( 22 )
Income Taxes
2025	$	41	$	17	$	29	$	( 2 )	$	—	$	85
2024	32		14		30		( 4 )		—		72
Net income (loss) attributable to common shareholders

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information


2025	$	156	$	55	$	82	$	( 2 )	$	—	$	291
2024	140		55		83		—		—		278
Supplemental segment information
Intersegment revenues (d)
2025	$	2	$	2	$	1	$	106	$	( 109 )	$	2
2024	2		2		1		103		( 105 )		3
Capital Expenditures
2025	$	221	$	125	$	96	$	2	$	—	$	444
2024	218		136		85		1		—		440

__________

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

(c) Interest expense, net and Interest expense to affiliates, net are primarily inclusive of Interest expense, which is partially offset by an immaterial amount of Interest income.

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

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.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information



	Three Months Ended September 30, 2025
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	1,365	$	735	$	684	$	1,147	$	501	$	283	$	363
Small commercial & industrial	645		167		113		210		56		72		82
Large commercial & industrial	217		101		172		406		331		32		43
Public authorities & electric railroads	14		8		8		16		8		4		4
Other (a)	229		78		122		235		98		77		62
Total electric revenues (b)	$	2,470	$	1,089	$	1,099	$	2,014	$	994	$	468	$	554
Natural gas revenues
Residential	$	—	$	50	$	68	$	13	$	—	$	13	$	—
Small commercial & industrial	—		23		14		7		—		7		—
Large commercial & industrial	—		1		37		1		—		1		—
Transportation	—		7		—		4		—		4		—
Other (c)	—		1		6		2		—		2		—
Total natural gas revenues (d)	$	—	$	82	$	125	$	27	$	—	$	27	$	—
Total revenues from contracts with customers	$	2,470	$	1,171	$	1,224	$	2,041	$	994	$	495	$	554
Other revenues
Revenues from alternative revenue programs	$	( 206 )	$	2	$	( 20 )	$	6	$	( 5 )	$	( 5 )	$	16
Other electric revenues (e)	11		6		4		4		3		1		—
Other natural gas revenues (e)	—		1		1		—		—		—		—

Total other revenues	$	( 195 )	$	9	$	( 15 )	$	10	$	( 2 )	$	( 4 )	$	16
Total revenues for reportable segments	$	2,275	$	1,180	$	1,209	$	2,051	$	992	$	491	$	570

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information



	Three Months Ended September 30, 2024
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	1,117	$	641	$	558	$	1,016	$	426	$	267	$	323
Small commercial & industrial	603		153		96		203		52		69		82
Large commercial & industrial	286		73		154		365		281		31		53
Public authorities & electric railroads	11		7		8		18		9		4		5
Other (a)	280		74		110		225		85		70		71
Total electric revenues (b)	$	2,297	$	948	$	926	$	1,827	$	853	$	441	$	534
Natural gas revenues
Residential	$	—	$	44	$	58	$	11	$	—	$	11	$	—
Small commercial & industrial	—		17		11		6		—		6		—
Large commercial & industrial	—		—		32		1		—		1		—
Transportation	—		7		—		4		—		4		—
Other (c)	—		2		3		1		—		1		—
Total natural gas revenues (d)	$	—	$	70	$	104	$	23	$	—	$	23	$	—
Total revenues from contracts with customers	$	2,297	$	1,018	$	1,030	$	1,850	$	853	$	464	$	534
Other revenues
Revenues from alternative revenue programs	$	( 76 )	$	5	$	9	$	8	$	5	$	( 3 )	$	6
Other electric revenues (e)	8		7		4		4		3		1		—
Other natural gas revenues (e)	—		—		1		—		—		—		—

Total other revenues	$	( 68 )	$	12	$	14	$	12	$	8	$	( 2 )	$	6
Total revenues for reportable segments	$	2,229	$	1,030	$	1,044	$	1,862	$	861	$	462	$	540

__________

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

(b) Includes operating revenues from affiliates in 2025 and 2024 respectively of:

• $ 2 million, $ 2 million at ComEd

• $ 2 million, $ 3 million at PECO

• $ 1 million , $ 2 million at BGE

• $ 2 million, $ 3 million at PHI

• $ 2 million, $ 2 million at Pepco

• $ 2 million, $ 2 million at DPL

• $ 1 million, $ 1 million at ACE

(d) Includes operating revenues from affiliates in 2025 and 2024 respectively of:

• $ 1 million, $ 1 million at PECO

• $ 1 million, $ 1 million at BGE

(e) Includes late payment charge revenues.

Nine Months Ended September 30, 2025 and 2024


	ComEd		PECO		BGE		PHI		Other (a)		Intersegment Eliminations		Exelon
Operating revenues (b) :
2025
Electric revenues	$	6,176	$	2,933	$	2,951	$	5,253	$	—	$	( 30 )	$	17,283
Natural gas revenues	—		580		840		148		—		( 5 )		1,563
Shared service and other revenues	—		—		—		7		1,381		( 1,388 )		—
Total operating revenues	$	6,176	$	3,513	$	3,791	$	5,408	$	1,381	$	( 1,423 )	$	18,846
2024

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information


Electric revenues	$	6,403	$	2,537	$	2,588	$	4,809	$	—	$	( 17 )	$	16,320
Natural gas revenues	—		438		680		122		—		( 3 )		1,237
Shared service and other revenues	—		—		—		7		1,369		( 1,376 )		—
Total operating revenues	$	6,403	$	2,975	$	3,268	$	4,938	$	1,369	$	( 1,396 )	$	17,557
Less:
Purchased power
2025	$	2,044	$	1,093	$	1,365	$	2,138	$	—	$	—	$	6,640
2024	2,504		977		1,108		1,895		( 1 )		—		6,483
Purchased fuel
2025	$	—	$	195	$	219	$	57	$	—	$	—	$	471
2024	—		136		120		44		1		—		301



Operating and maintenance
2025	$	958	$	690	$	621	$	876	$	1,313	$	( 618 )	$	3,840
2024	970		695		613		780		1,277		( 579 )		3,756
Operating and maintenance from affiliates
2025	$	296	$	182	$	186	$	148	$	32	$	( 844 )	$	—
2024	307		181		182		147		29		( 846 )		—
Depreciation and amortization
2025	$	1,162	$	336	$	473	$	701	$	45	$	—	$	2,717
2024	1,124		318		474		716		49		—		2,681

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information


Taxes other than income taxes
2025	$	303	$	183	$	273	$	426	$	31	$	—	$	1,216
2024	287		164		254		395		27		—		1,127
(Gain) on sale of assets
2025	$	—	$	—	$	—	$	( 1 )	$	—	$	—	$	( 1 )
2024	( 5 )		( 4 )		—		—		( 3 )		—		( 12 )
Interest expense, net (c)
2025	$	385	$	179	$	183	$	303	$	510	$	—	$	1,560
2024	364		161		159		279		469		( 4 )		1,428
Interest expense to affiliates, net (c)
2025	$	10	$	9	$	—	$	2	$	( 1 )	$	( 2 )	$	18
2024	10		9		—		—		( 3 )		2		18
Other, net
2025	$	( 86 )	$	( 29 )	$	( 35 )	$	( 54 )	$	( 22 )	$	41	$	( 185 )
2024	( 66 )		( 27 )		( 27 )		( 79 )		( 28 )		31		( 196 )
Income taxes
2025	$	201	$	23	$	108	$	184	$	( 120 )	$	—	$	396
2024	85		9		32		158		( 126 )		—		158
Net income (loss) attributable to common shareholders
2025	$	903	$	652	$	398	$	628	$	( 407 )	$	—	$	2,174
2024	823		356		353		603		( 322 )		—		1,813
Supplemental segment information
Intersegment revenues (d)
2025	$	19	$	9	$	6	$	7	$	1,374	$	( 1,415 )	$	—
2024	6		7		7		7		1,362		( 1,389 )		—
Capital expenditures
2025	$	1,970	$	1,334	$	1,211	$	1,552	$	28	$	—	$	6,095
2024	1,619		1,125		1,033		1,343		41		—		5,161
Total assets
September 30, 2025	$	47,010	$	19,227	$	16,742	$	28,947	$	5,365	$	( 3,752 )	$	113,539
December 31, 2024	44,750		17,123		15,542		28,297		6,012		( 3,940 )		107,784

__________

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

(c) Interest expense, net and Interest expense to affiliates, net are primarily inclusive of Interest expense, which is partially offset by an immaterial amount of Interest income.

(d) See Note 15 — Related Party Transactions for additional information on intersegment revenues.

PHI:


	Pepco		DPL		ACE		Other (a)		Intersegment Eliminations		PHI
Operating revenues (b) :
2025
Electric revenues	$	2,626	$	1,312	$	1,328	$	—	$	( 13 )	$	5,253
Natural gas revenues	—		148		—		—		—		148
Shared service and other revenues	—		—		—		323		( 316 )		7

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information


Total operating revenues	$	2,626	$	1,460	$	1,328	$	323	$	( 329 )	$	5,408
2024
Electric revenues	$	2,320	$	1,221	$	1,280	$	—	$	( 12 )	$	4,809
Natural gas revenues	—		122		—		—		—		122
Shared service and other revenues	—		—		—		328		( 321 )		7
Total operating revenues	$	2,320	$	1,343	$	1,280	$	328	$	( 333 )	$	4,938
Less:
Purchased power
2025	$	942	$	580	$	616	$	—	$	—	$	2,138
2024	808		529		557		1		—		1,895
Purchased fuel
2025	$	—	$	57	$	—	$	—	$	—	$	57
2024	—		44		—		—		—		44



Operating and maintenance
2025	$	282	$	162	$	161	$	271	$	—	$	876
2024	206		151		155		268		—		780
Operating and maintenance from affiliates
2025	$	184	$	134	$	116	$	43	$	( 329 )	$	148
2024	186		133		119		41		( 332 )		147
Depreciation and amortization
2025	$	321	$	189	$	188	$	3	$	—	$	701
2024	307		183		214		12		—		716
Taxes other than income taxes
2025	$	344	$	63	$	7	$	12	$	—	$	426
2024	317		59		7		12		—		395
(Gain) on sale of assets
2025	$	( 1 )	$	—	$	—	$	—	$	—	$	( 1 )
2024	—		—		—		—		—		—
Interest expense, net (c)
2025	$	159	$	75	$	62	$	7	$	—	$	303
2024	142		69		59		7		2		279
Interest expense to affiliates, net (c)
2025	$	—	$	—	$	—	$	2	$	—	$	2
2024	—		—		—		3		( 3 )		—
Other, net
2025	$	( 31 )	$	( 12 )	$	( 8 )	$	( 3 )	$	—	$	( 54 )
2024	( 43 )		( 20 )		( 12 )		( 4 )		—		( 79 )
Income taxes
2025	$	89	$	49	$	48	$	( 2 )	$	—	$	184
2024	74		39		48		( 3 )		—		158
Net income (loss) attributable to common shareholders
2025	$	337	$	163	$	138	$	( 10 )	$	—	$	628
2024	323		156		133		( 9 )		—		603
Supplemental segment information
Intersegment revenues (d)
2025	$	4	$	6	$	3	$	323	$	( 329 )	$	7
2024	5		5		2		328		( 333 )		7
Capital expenditures

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information


2025	$	690	$	402	$	292	$	168	$	—	$	1,552
2024	672		404		265		2		—		1,343
Total assets
September 30, 2025	$	12,326	$	6,540	$	5,516	$	4,604	$	( 39 )	$	28,947
December 31, 2024	12,000		6,421		5,349		4,567		( 40 )		28,297

__________

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

(c) Interest expense, net and Interest expense to affiliates, net are primarily inclusive of Interest expense, which is partially offset by an immaterial amount of Interest income.

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

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



	Nine Months Ended September 30, 2025
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	3,452	$	1,921	$	1,829	$	2,847	$	1,273	$	792	$	782
Small commercial & industrial	1,799		484		311		548		155		200		193
Large commercial & industrial	689		260		456		1,144		911		92		141
Public authorities & electric railroads	43		26		25		56		29		13		14
Other (a)	688		231		352		688		274		224		196
Total electric revenues (b)	$	6,671	$	2,922	$	2,973	$	5,283	$	2,642	$	1,321	$	1,326
Natural gas revenues
Residential	$	—	$	396	$	555	$	86	$	—	$	86	$	—
Small commercial & industrial	—		140		100		35		—		35		—
Large commercial & industrial	—		1		178		6		—		6		—
Transportation	—		28		—		13		—		13		—
Other (c)	—		13		37		8		—		8		—
Total natural gas revenues (d)	$	—	$	578	$	870	$	148	$	—	$	148	$	—
Total revenues from contracts with customers	$	6,671	$	3,500	$	3,843	$	5,431	$	2,642	$	1,469	$	1,326
Other revenues
Revenues from alternative revenue programs	$	( 525 )	$	( 6 )	$	( 63 )	$	( 27 )	$	( 19 )	$	( 10 )	$	2
Other electric revenues (e)	30		17		9		4		3		1		—
Other natural gas revenues (e)	—		2		2		—		—		—		—

Total other revenues	$	( 495 )	$	13	$	( 52 )	$	( 23 )	$	( 16 )	$	( 9 )	$	2
Total revenues for reportable segments	$	6,176	$	3,513	$	3,791	$	5,408	$	2,626	$	1,460	$	1,328

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information



	Nine Months Ended September 30, 2024
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	3,017	$	1,683	$	1,556	$	2,537	$	1,085	$	725	$	727
Small commercial & industrial	1,755		407		274		519		141		191		187
Large commercial & industrial	875		191		425		1,034		794		91		149
Public authorities & electric railroads	43		21		24		52		26		12		14
Other (a)	803		221		303		623		224		198		206
Total electric revenues (b)	$	6,493	$	2,523	$	2,582	$	4,765	$	2,270	$	1,217	$	1,283
Natural gas revenues
Residential	$	—	$	300	$	418	$	72	$	—	$	72	$	—
Small commercial & industrial	—		106		76		29		—		29		—
Large commercial & industrial	—		—		143		4		—		4		—
Transportation	—		20		—		12		—		12		—
Other (c)	—		11		12		5		—		5		—
Total natural gas revenues (d)	$	—	$	437	$	649	$	122	$	—	$	122	$	—
Total revenues from contracts with customers	$	6,493	$	2,960	$	3,231	$	4,887	$	2,270	$	1,339	$	1,283
Other revenues
Revenues from alternative revenue programs	$	( 100 )	$	3	$	28	$	40	$	42	$	1	$	( 3 )
Other electric revenues (e)	10		11		7		11		8		3		—
Other natural gas revenues (e)	—		1		2		—		—		—		—

Total other revenues	$	( 90 )	$	15	$	37	$	51	$	50	$	4	$	( 3 )
Total revenues for reportable segments	$	6,403	$	2,975	$	3,268	$	4,938	$	2,320	$	1,343	$	1,280

__________

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

(b) Includes operating revenues from affiliates in 2025 and 2024 respectively of:

• $ 19 million, $ 6 million at ComEd

• $ 7 million, $ 5 million at PECO

• $ 4 million, $ 4 million at BGE

• $ 7 million, $ 7 million at PHI

• $ 4 million, $ 5 million at Pepco

• $ 6 million, $ 5 million at DPL

• $ 3 million, $ 2 million at ACE

(d) Includes operating revenues from affiliates in 2025 and 2024 respectively of:

• $ 2 million, $ 2 million at PECO

• $ 2 million, $ 3 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 — Accounts Receivable

5. 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 September 30, 2025
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at June 30, 2025	$	465	$	122	$	154	$	66	$	123	$	69	$	21	$	33
Plus: Current period provision for expected credit losses (a)(b)	82		37		22		8		15		11		3		1
Less: Write-offs (c)(d) , net of recoveries (e)	96		44		31		6		15		8		4		3
Balance at September 30, 2025	$	451	$	115	$	145	$	68	$	123	$	72	$	20	$	31

	Three Months Ended September 30, 2024
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at June 30, 2024	$	372	$	112	$	112	$	45	$	103	$	53	$	16	$	34
Plus: Current period provision for expected credit losses	84		16		28		20		20		12		4		4
Less: Write-offs, net of recoveries	30		7		5		5		13		7		3		3
Balance at September 30, 2024	$	426	$	121	$	135	$	60	$	110	$	58	$	17	$	35

	Nine Months Ended September 30, 2025
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2024	$	406	$	109	$	133	$	56	$	108	$	59	$	17	$	32
Plus: Current period provision for expected credit losses (f)(g)(h)	224		66		68		34		56		35		13		8
Less: Write-offs (i) , net of recoveries (e)	179		60		56		22		41		22		10		9
Balance at September 30, 2025	$	451	$	115	$	145	$	68	$	123	$	72	$	20	$	31

	Nine Months Ended September 30, 2024
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2023	$	317	$	69	$	95	$	46	$	107	$	52	$	19	$	36
Plus: Current period provision for expected credit losses	221		77		63		34		47		30		8		9
Less: Write-offs, net of recoveries	112		25		23		20		44		24		10		10
Balance at September 30, 2024	$	426	$	121	$	135	$	60	$	110	$	58	$	17	$	35

_________

(a) For ComEd, the increase is primarily a result of increased aging of receivables.

(b) For PECO, BGE, and ACE, the decrease is primarily a result of decreased receivable balances.

(d) For PECO, the increase is primarily a result of increased disconnection activities.

(e) Recoveries were not material to the Registrants.

(f) For ComEd, the decrease is primarily a result of increased disconnection activities.

(g) For PECO, Pepco, and DPL, the increase is primarily a result of increased receivable balances.

(h) For ACE, the decrease is primarily a result of decreased receivable balances.

(i) For ComEd and PECO, the increase is primarily a result of increased disconnection activities.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 5 — Accounts Receivable

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


	Three Months Ended September 30, 2025
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at June 30, 2025	$	107	$	31	$	19	$	5	$	52	$	28	$	9	$	15
Plus: Current period provision (benefit) for expected credit losses (a)(b)	7		5		2		1		( 1 )		—		—		( 1 )
Less: Write-offs (c) , net of recoveries (d)	16		11		4		1		—		—		—		—
Balance at September 30, 2025	$	98	$	25	$	17	$	5	$	51	$	28	$	9	$	14

	Three Months Ended September 30, 2024
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at June 30, 2024	$	108	$	29	$	20	$	5	$	54	$	34	$	7	$	13
Plus: Current period provision (benefit) for expected credit losses	7		10		1		3		( 7 )		( 8 )		—		1
Less: Write-offs, net of recoveries	4		—		1		2		1		—		—		1
Balance at September 30, 2024	$	111	$	39	$	20	$	6	$	46	$	26	$	7	$	13

	Nine Months Ended September 30, 2025
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2024	$	107	$	34	$	18	$	6	$	49	$	27	$	9	$	13
Plus: Current period provision (benefit) for expected credit losses (e)(f)	15		4		9		( 1 )		3		1		—		2
Less: Write-offs (g)(h) , net of recoveries (d)	24		13		10		—		1		—		—		1
Balance at September 30, 2025	$	98	$	25	$	17	$	5	$	51	$	28	$	9	$	14

	Nine Months Ended September 30, 2024
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2023	$	82	$	17	$	8	$	7	$	50	$	28	$	8	$	14
Plus: Current period provision (benefit) for expected credit losses	43		25		15		4		( 1 )		( 2 )		( 1 )		2
Less: Write-offs, net of recoveries	14		3		3		5		3		—		—		3
Balance at September 30, 2024	$	111	$	39	$	20	$	6	$	46	$	26	$	7	$	13

_________

(a) For Pepco, the increase is primarily due to changes in risk profile.

(b) For ACE, the decrease is primarily a result of decreased receivable balances.

(d) Recoveries were not material to the Registrants.

(e) For ComEd, the decrease is primarily a result of decreased aging of receivables.

(f) For PECO and BGE, the decrease is primarily a result of decreased receivable balances.

(g) For ComEd and PECO, the increase is primarily a result of increased disconnection activities.

(h) For BGE and ACE, the decrease is primarily a result of increased collection activities.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 5 — Accounts Receivable

Unbilled Customer Revenue

The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of September 30, 2025 and December 31, 2024.


	Unbilled customer revenues (a)
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2025	$	1,002	$	401	$	207	$	178	$	216	$	111	$	51	$	54
December 31, 2024	1,114		335		254		257		268		121		76		71

__________

(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

For the nine months ended September 30, 2025 and 2024, the Utility Registrants were 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 participated in the utilities' consolidated billing. The following table presents the total receivables purchased.


	Total receivables purchased
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine months ended September 30, 2025	$	3,320	$	814	$	954	$	550	$	1,002	$	624	$	201	$	177
Nine months ended September 30, 2024	3,177		750		854		606		967		607		191		169

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 6 — Income Taxes

6. Income Taxes (All Registrants)

Rate Reconciliation

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


	Three Months Ended September 30, 2025 (a)
	Exelon		ComEd (b)		PECO (c)		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	5.7		7.4		( 1.4 )		6.3		6.5		6.4		6.5		7.1
Plant basis differences	( 5.1 )		( 0.9 )		( 16.0 )		( 1.3 )		( 0.6 )		( 0.9 )		( 0.4 )		( 0.1 )
Excess deferred tax amortization	( 6.4 )		( 8.9 )		( 1.6 )		( 4.1 )		( 4.0 )		( 5.4 )		( 3.2 )		( 1.7 )
Amortization of investment tax credit, including deferred taxes on basis difference	—		( 0.1 )		—		—		—		—		( 0.1 )		( 0.1 )
Tax credits	( 0.3 )		( 0.1 )		—		( 0.6 )		( 0.4 )		( 0.2 )		( 0.5 )		( 0.3 )
Other	0.1		( 0.2 )		—		0.6		0.1		( 0.1 )		0.3		0.2
Effective income tax rate	15.0	%	18.2	%	2.0	%	21.9	%	22.6	%	20.8	%	23.6	%	26.1	%


	Three Months Ended September 30, 2024 (a)
	Exelon		ComEd (b)		PECO (c)		BGE (d)		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	5.7		7.6		( 2.1 )		6.5		6.5		6.2		6.3		7.4
Plant basis differences	( 4.8 )		( 0.8 )		( 19.5 )		( 0.8 )		( 0.8 )		( 1.2 )		( 0.8 )		—
Excess deferred tax amortization	( 14.0 )		( 16.6 )		( 2.6 )		( 18.6 )		( 5.5 )		( 6.7 )		( 5.9 )		( 1.6 )
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	( 0.9 )		( 2.6 )		—		( 0.6 )		( 0.6 )		( 0.5 )		( 0.6 )		( 0.5 )
Other	( 0.3 )		0.6		( 0.3 )		0.8		0.1		( 0.2 )		0.4		0.3
Effective income tax rate	6.6	%	9.1	%	( 3.5 )	%	8.2	%	20.6	%	18.6	%	20.3	%	26.5	%

__________

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

(b) For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits.

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

(d) 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.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 6 — Income Taxes


	Nine Months Ended September 30, 2025 (a)
	Exelon		ComEd (b)		PECO (c)		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	5.6		7.5		( 2.3 )		6.2		6.6		6.4		6.4		7.1
Plant basis differences	( 4.6 )		( 0.9 )		( 14.0 )		( 1.5 )		( 0.6 )		( 0.9 )		( 0.5 )		( 0.1 )
Excess deferred tax amortization	( 6.5 )		( 9.0 )		( 1.6 )		( 4.1 )		( 4.1 )		( 5.4 )		( 3.5 )		( 1.6 )
Amortization of investment tax credit, including deferred taxes on basis difference	—		( 0.1 )		—		—		—		—		( 0.1 )		( 0.1 )
Tax credits	( 0.4 )		( 0.4 )		—		( 0.4 )		( 0.4 )		( 0.3 )		( 0.3 )		( 0.3 )
Other	0.3		0.1		0.3		0.1		0.2		0.1		0.1		( 0.2 )
Effective income tax rate	15.4	%	18.2	%	3.4	%	21.3	%	22.7	%	20.9	%	23.1	%	25.8	%


	Nine Months Ended September 30, 2024 (a)
	Exelon		ComEd (b)		PECO (c)		BGE (d)		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	5.8		7.7		( 1.2 )		6.3		6.5		6.2		6.2		7.4
Plant basis differences	( 4.2 )		( 0.8 )		( 14.7 )		( 1.2 )		( 0.9 )		( 1.3 )		( 0.9 )		0.1
Excess deferred tax amortization	( 14.1 )		( 17.4 )		( 2.4 )		( 17.6 )		( 5.4 )		( 6.8 )		( 5.8 )		( 1.6 )
Amortization of investment tax credit, including deferred taxes on basis difference	( 0.1 )		( 0.1 )		—		—		( 0.1 )		—		( 0.1 )		( 0.1 )
Tax credits	( 0.6 )		( 1.4 )		—		( 0.4 )		( 0.5 )		( 0.4 )		( 0.4 )		( 0.4 )
Other	0.2		0.4		( 0.2 )		0.2		0.2		( 0.1 )		—		0.1
Effective income tax rate	8.0	%	9.4	%	2.5	%	8.3	%	20.8	%	18.6	%	20.0	%	26.5	%

__________

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

(b) For ComEd, the lower effective tax rate is primarily due to CEJA which resulted in the acceleration of certain income tax benefits.

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

(d) 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.

Unrecognized Tax Benefits

Exelon, PHI and DPL have the following unrecognized tax benefits at September 30, 2025 and December 31, 2024. ComEd's, PECO's, BGE's, Pepco's, and ACE's amounts are not material.


	Exelon (a)		PHI		DPL
September 30, 2025	$	97	$	47	$	11
December 31, 2024	96		48		12

__________

(a) At September 30, 2025 and December 31, 2024, Exelon's unrecognized tax benefits is inclusive of $ 31 million related to Constellation's share of unrecognized tax benefits for periods prior to the separation. Exelon reflected an offsetting receivable of $ 31 million in Other deferred debits and other assets in the Consolidated Balance Sheet for these amounts.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 6 — Income Taxes

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

At September 30, 2025, Exelon, PHI, and DPL have approximately $ 64 million, $ 6 million, and $ 1 million, respectively, of unrecognized federal tax benefits that could significantly change within the 12 months after the reporting date based on the outcome of pending refund claims that impacts the effective tax rate.

Other Tax Matters

One Big Beautiful Bill Act (All Registrants)

On July 4, 2025, the OBBBA was signed into law. The bill permanently extends expiring tax benefits of the TCJA and provides additional tax relief for individuals and businesses while accelerating the phase-out and curtailment for renewable energy tax credits enacted by the IRA. The tax law changes enacted as part of OBBBA will not have a direct material impact on the Registrants’ financial statements.

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.

Beginning in 2023, based on the existing statute, 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.

On September 12, 2024, the U.S. Treasury issued proposed regulations providing further guidance addressing the implementation of CAMT. The proposed regulations are consistent with Exelon’s prior interpretation and therefore there are no financial statement impacts.

On September 30, 2025, the U.S. Treasury issued interim guidance addressing the implementation of CAMT in the form of a notice. The guidance allows entities with regulated operations a repairs adjustment for CAMT purposes, however the provision was drafted in a manner that does not achieve that intended result. Thus, the guidance does not benefit Exelon and has no financial statement impact. Exelon will continue to monitor and assess the potential financial statement impacts of future regulations or other guidance when issued.

Allocation of Tax Benefits (All Registrants)

The Utility Registrants are party to an agreement with Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the Utility Registrants. That allocation is treated as a contribution to capital from Exelon to the party receiving the benefit.

The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement, for the three and nine months ended September 30, 2025, and 2024.


	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2025	$	20	$	14	$	12	$	23	$	12	$	7	$	4
September 30, 2024	30		15		14		16		9		5		2

Allocation of Income Taxes to Regulated Utilities (All Registrants)

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 6 — Income Taxes

purposes the tax benefit of NOLC should be reflected on a separate company basis not taking into consideration the utilization of losses by other affiliates. A PLR issued to another taxpayer may not be relied on as precedent.

For the Utility Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that are being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes. The Utility Registrants, except for PECO, filed PLR requests with the IRS confirming the treatment of the NOLC for ratemaking purposes. The Utility Registrants will record the impact, if any, upon receiving the PLR from the IRS.

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 Exelon tax sharing agreement when Constellation was included in Exelon's consolidated group. At September 30, 2025, there is no balance due to or from 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 Exelon tax sharing agreement when Constellation was included in Exelon's consolidated group. At September 30, 2025, there is no balance due to or from Constellation.

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 also provides that Exelon will reimburse Constellation when those allocated tax attribute carryforwards are utilized. In 2025, Exelon remitted $ 127 million of payments to Constellation for the utilization of pre-closing tax credit carryforwards. At September 30, 2025, Exelon recorded a payable of $ 175 million and $ 38 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.

7. Retirement Benefits (All Registrants)

Defined Benefit Pension and OPEB

The majority of the 2025 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 5.68 %. The majority of the 2025 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 5.64 %.

During the first quarter of 2025, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2025. This valuation resulted in an increase to the pension obligation of $ 1 million and an increase to the OPEB obligation and asset of $ 6 million and $ 2 million, respectively. Additionally, AOCI decreased by $ 5 million (after-tax) and regulatory assets increased by $ 8 million and liabilities decreased by $ 3 million.

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, 2025 and 2024.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 7 — Retirement Benefits


	Pension Benefits				OPEB
	Three Months Ended September 30,				Three Months Ended September 30,
	2025		2024		2025		2024
Components of net periodic benefit cost
Service cost	$	38	$	43	$	7	$	6
Interest cost	146		141		26		24
Expected return on assets	( 179 )		( 184 )		( 21 )		( 21 )
Amortization of:
Prior service cost (credit)	1		1		( 2 )		( 2 )
Actuarial loss (gain)	53		53		( 1 )		—


Net periodic benefit cost	$	59	$	54	$	9	$	7

	Pension Benefits				OPEB
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Components of net periodic benefit cost
Service cost	$	115	$	125	$	19	$	20
Interest cost	439		423		76		72
Expected return on assets	( 535 )		( 552 )		( 63 )		( 63 )
Amortization of:
Prior service cost (credit)	2		2		( 6 )		( 6 )
Actuarial loss (gain)	159		160		( 2 )		—


Net periodic benefit cost	$	180	$	158	$	24	$	23

The amounts below represent the Registrants' allocated pension and OPEB costs (benefits). 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 PHI and each of the Utility Registrants, which 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.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 7 — Retirement Benefits


	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and OPEB Costs (Benefits)	2025		2024		2025		2024
Exelon	$	68	$	61	$	204	$	181
ComEd	22		17		64		53
PECO	2		( 1 )		5		( 1 )
BGE	16		14		46		45
PHI	23		25		72		71
Pepco	8		8		26		24
DPL	4		4		12		11
ACE	3		3		10		10

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 nine months ended September 30, 2025 and 2024.


	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plan Employer Contributions	2025		2024		2025		2024
Exelon	$	30	$	25	$	86	$	76
ComEd	12		12		34		32
PECO	4		3		12		11
BGE	3		2		9		8
PHI	5		4		15		12
Pepco	1		1		4		3
DPL	1		1		3		3
ACE	1		1		2		2

8. 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. 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.

Commodity Price Risk

The Utility 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

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 8 — Derivative Financial Instruments

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 purchases associated with forecasted gas supply requirements.
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 2024 Form 10-K for additional information.

(b) The fair value of the DPL economic hedge is not material at September 30, 2025 and December 31, 2024.

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 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. A hypothetical 50 basis point change in the interest rates associated with Exelon's interest rate swaps as of September 30, 2025 would result in an immaterial impact to Exelon's Consolidated Net income.

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 8 — Derivative Financial Instruments

Below is a summary of the interest rate hedge balances at September 30, 2025 and December 31, 2024 .


	Derivatives Designated as Hedging Instruments
	September 30, 2025		December 31, 2024
Other current assets	$	—	$	14
Other deferred debits (noncurrent assets)	2		12
Total derivative assets	2		26
Mark-to-market derivative liabilities (current liabilities)	—		( 1 )
Mark-to-market derivative liabilities (noncurrent liabilities)	( 8 )		—
Total mark-to-market derivative liabilities	( 8 )		( 1 )
Total mark-to-market derivative net assets (liabilities)	$	( 6 )	$	25

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 February 2025, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $ 765 million upon issuance of $ 1 billion of debt. See Note 9 – Debt and Credit Agreements for additional information on the debt issuance. The settlements resulted in a cash receipt of $ 16 million. The accumulated AOCI gain of $ 13 million (net of tax) 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. During the third quarter of 2025, Exelon Corporate entered into $ 30 million notional of 5-year maturity floating-to-fixed swaps and $ 30 million notional of 10-year maturity floating-to-fixed swaps, for a total notional of $ 60 million designated as cash flow hedges. The following table provides the notional amounts outstanding held by Exelon at September 30, 2025 and December 31, 2024.


	September 30, 2025		December 31, 2024
5-year maturity floating-to-fixed swaps	$	335	$	657
10-year maturity floating-to-fixed swaps	335		658
Total	$	670	$	1,315

The related AOCI derivative loss for the three and nine months ended September 30, 2025 was $ 1 million and $ 14 million (net of tax), respectively. The related AOCI derivative loss for the three and nine months ended September 30, 2024 was $ 29 million and $ 30 million (net of tax), respectively. See Note 13 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.

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 remained relatively consistent as of September 30, 2025. Cash collateral held by ComEd, 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. The following table reflects the Registrants' cash collateral held from external counterparties, which is recorded in Other current liabilities on their respective Consolidated Balance Sheets, as of September 30, 2025 and December 31, 2024:

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 8 — Derivative Financial Instruments


	September 30, 2025		December 31, 2024
Exelon	$	196	$	181
ComEd	184		176
PECO (a)	6		—
BGE	2		1
PHI	5		4
Pepco	3		1
DPL	2		2
ACE (b)	—		—

__________

(a) PECO had less than one million in cash collateral held from external parties at December 31, 2024.

(b) ACE had less than one million in cash collateral with external parties at September 30, 2025 and December 31, 2024.

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. As of September 30, 2025, 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 September 30, 2025, they could have been required to post collateral to their counterparties of $ 40 million, $ 23 million, and $ 13 million, respectively.

9. 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 September 30, 2025 and December 31, 2024.


	Outstanding Commercial Paper at				Average Interest Rate on Commercial Paper Borrowings at
Commercial Paper Issuer	September 30, 2025		December 31, 2024		September 30, 2025		December 31, 2024
Exelon (a)	$	580	$	1,359	4.29	%	4.66	%
ComEd	$	—	$	36	—	%	4.55	%
PECO	$	—	$	192	—	%	4.65	%
BGE	$	—	$	175	—	%	4.61	%
PHI (b)	$	166	$	530	4.30	%	4.70	%

Pepco	$	63	$	200	4.30	%	4.69	%
DPL	$	33	$	144	4.27	%	4.74	%
ACE	$	70	$	186	4.30	%	4.67	%

__________

(a) Exelon Corporate had $ 414 million outstanding commercial paper borrowings at September 30, 2025 and $ 426 million in outstanding commercial paper borrowings at December 31, 2024.

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

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 9 — Debt and Credit Agreements

Revolving Credit Agreements

On August 29, 2024, Exelon Corporate and each of the Utility Registrants amended and restated their respective syndicated revolving credit facility, extending the maturity date to August 29, 2029. The following table reflects the credit agreements:


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

Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of September 30, 2025.

The Utility Registrants have credit facility agreements, arranged at community banks, which may be 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. On October 3, 2025, the Utility Registrants amended and extended their credit facilities at community banks. Previously structured as one-year arrangements, the facilities are now two-year terms. These facilities expire on October 1, 2027.

See Note 16 — Debt and Credit Agreements of the 2024 Form 10-K for additional information on the Registrants' credit facilities.

Short-Term Loan Agreements

On March 14, 2024, Exelon Corporate amended and bifurcated the $ 500 million term loan agreement into two tranches of $ 350 million and $ 150 million. The loan agreements were renewed in the first quarter of 2025, extending the expiration date to March 13, 2026. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 1.00 % and all indebtedness thereunder is unsecured. The loan agreements are reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 9 — Debt and Credit Agreements

Long-Term Debt

Issuance of Long-Term Debt

During the nine months ended September 30, 2025, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Junior Subordinated Notes (a)

6.50 %

March 15, 2055

$ 1,000

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

Exelon

Notes

5.125 %

March 15, 2031

$ 500

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

Exelon

Notes

5.875 %

March 15, 2055

$ 500

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

ComEd

First Mortgage Bonds

5.95 %

June 1, 2055

$ 725

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

PECO

First Mortgage Bonds

4.875 %

September 15, 2035

$ 525

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

PECO

First Mortgage Bonds

5.65 %

September 15, 2055

$ 525

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

BGE

Notes

5.45 %

June 1, 2035

$ 650

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

Pepco

First Mortgage Bonds

5.78 %

September 17, 2055

$ 75

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.48 %

March 26, 2040

$ 200

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

5.28 %

March 26, 2035

$ 125

Repay existing indebtedness and for general corporate purposes.

ACE (b)

First Mortgage Bonds

5.28 %

March 26, 2035

$ 100

Repay existing indebtedness and for general corporate purposes.

__________

(a) The Junior Subordinated Notes bear interest at 6.50 % per annum, commencing February 19, 2025 to, but excluding March 15, 2035. Thereafter, the interest rate resets every five years on March 15 and will be set at a rate per annum equal to the Five-year U.S. Treasury Rate plus a spread of 1.975 %.

(b) On March 26, 2025, ACE entered into a purchase agreement of First Mortgage Bonds of $ 75 million and $ 75 million at 5.54 % and 5.81 % due on November 19, 2040 and November 19, 2055, respectively. The closing date of the issuance is expected to occur in November 2025.

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 9 — Debt and Credit Agreements

Reoffering of Tax-Exempt Bonds

On July 1, 2025, DPL completed the reoffering of $ 78.4 million aggregate principal amount of its Delaware Economic Development Authority’s Gas Facilities Refunding Revenue Bonds (Delmarva Power & Light Company Project) 2020 Series A (Non-AMT) (the "Bonds"). In connection with the reoffering of the Bonds, the interest rate was modified to 3.60 % per annum, and the maturity date was modified to January 1, 2031. DPL did not directly receive any proceeds from the reoffering.

Debt Covenants

As of September 30, 2025, the Registrants are in compliance with debt covenants.

10. 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.

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 2024 Form 10-K.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities

Fair Value of Financial Liabilities Recorded at Amortized Cost

The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of September 30, 2025 and December 31, 2024. The Registrants have no financial liabilities 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.


	September 30, 2025										December 31, 2024
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
			Level 1		Level 2		Level 3		Total				Level 1		Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year (a)
Exelon	$	48,451	$	—	$	40,212	$	4,358	$	44,570	$	44,400	$	—	$	35,337	$	3,720	$	39,057
ComEd	12,751		—		11,371		—		11,371		12,030		—		10,260		—		10,260
PECO	6,746		—		6,019		—		6,019		5,704		—		4,816		—		4,816
BGE	6,041		—		5,549		—		5,549		5,395		—		4,702		—		4,702
PHI	9,599		—		4,240		4,358		8,598		9,124		—		4,093		3,720		7,813
Pepco	4,632		—		2,551		1,877		4,428		4,362		—		2,475		1,544		4,019
DPL	2,344		—		662		1,423		2,085		2,220		—		623		1,250		1,873
ACE	2,035		—		811		1,059		1,870		1,933		—		787		925		1,712
Long-Term Debt to Financing Trusts
Exelon	$	390	$	—	$	—	$	403	$	403	$	390	$	—	$	—	$	396	$	396
ComEd	206		—		—		215		215		206		—		—		208		208
PECO	184		—		—		188		188		184		—		—		188		188

__________

(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 2024 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 2024 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 10 — 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 September 30, 2025 and December 31, 2024. Exelon and the Utility Registrants have immaterial and no financial assets or liabilities measured using the NAV practical expedient, respectively:

Exelon


	At September 30, 2025						At December 31, 2024
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents (a)	$	1,741	$	—	$	—	$	1,741	$	544	$	—	$	—	$	544
Rabbi trust investments
Cash equivalents	99		—		—		99		94		—		—		94
Mutual funds	68		—		—		68		65		—		—		65
Fixed income	—		6		—		6		—		6		—		6
Life insurance contracts	—		76		23		99		—		73		22		95
Rabbi trust investments subtotal	167		82		23		272		159		79		22		260

Interest rate derivative assets
Derivatives designated as hedging instruments	—		2		—		2		—		26		—		26

Interest rate derivative assets subtotal	—		2		—		2		—		26		—		26
Total assets	1,908		84		23		2,015		703		105		22		830
Liabilities
Commodity derivative liabilities	—		—		( 128 )		( 128 )		—		—		( 132 )		( 132 )
Interest rate derivative liabilities
Derivatives designated as hedging instruments	—		( 8 )		—		( 8 )		—		( 1 )		—		( 1 )

Interest rate derivative liabilities subtotal	—		( 8 )		—		( 8 )		—		( 1 )		—		( 1 )
Deferred compensation obligation	—		( 69 )		—		( 69 )		—		( 74 )		—		( 74 )
Total liabilities	—		( 77 )		( 128 )		( 205 )		—		( 75 )		( 132 )		( 207 )
Total net assets (liabilities)	$	1,908	$	7	$	( 105 )	$	1,810	$	703	$	30	$	( 110 )	$	623

__________

(a) Exelon excludes cash of $ 170 million and $ 219 million at September 30, 2025 and December 31, 2024, respectively, and restricted cash of $ 187 million and $ 176 million at September 30, 2025 and December 31, 2024, respectively, and includes long-term restricted cash of $ 49 million and $ 41 million at September 30, 2025 and December 31, 2024, 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 10 — Fair Value of Financial Assets and Liabilities

ComEd, PECO, and BGE


	ComEd								PECO								BGE
At September 30, 2025	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)	$	653	$	—	$	—	$	653	$	340	$	—	$	—	$	340	$	659	$	—	$	—	$	659
Rabbi trust investments

Mutual funds	—		—		—		—		12		—		—		12		10		—		—		10
Life insurance contracts	—		—		—		—		—		23		—		23		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		12		23		—		35		10		—		—		10

Total assets	653		—		—		653		352		23		—		375		669		—		—		669
Liabilities
Commodity derivative liabilities (b)	—		—		( 128 )		( 128 )		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		( 9 )		—		( 9 )		—		( 7 )		—		( 7 )		—		( 4 )		—		( 4 )
Total liabilities	—		( 9 )		( 128 )		( 137 )		—		( 7 )		—		( 7 )		—		( 4 )		—		( 4 )
Total net assets (liabilities)	$	653	$	( 9 )	$	( 128 )	$	516	$	352	$	16	$	—	$	368	$	669	$	( 4 )	$	—	$	665


	ComEd								PECO								BGE
At December 31, 2024	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)	$	390	$	—	$	—	$	390	$	29	$	—	$	—	$	29	$	1	$	—	$	—	$	1
Rabbi trust investments
Mutual funds	—		—		—		—		12		—		—		12		10		—		—		10
Life insurance contracts	—		—		—		—		—		22		—		22		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		12		22		—		34		10		—		—		10
Total assets	390		—		—		390		41		22		—		63		11		—		—		11
Liabilities
Commodity derivative liabilities (b)	—		—		( 132 )		( 132 )		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		( 8 )		—		( 8 )		—		( 7 )		—		( 7 )		—		( 4 )		—		( 4 )
Total liabilities	—		( 8 )		( 132 )		( 140 )		—		( 7 )		—		( 7 )		—		( 4 )		—		( 4 )
Total net assets (liabilities)	$	390	$	( 8 )	$	( 132 )	$	250	$	41	$	15	$	—	$	56	$	11	$	( 4 )	$	—	$	7

__________

(a) ComEd excludes cash of $ 70 million and $ 66 million at September 30, 2025 and December 31, 2024, respectively, and restricted cash of $ 184 million and $ 176 million at September 30, 2025 and December 31, 2024, respectively. Additionally, ComEd includes long-term restricted cash of $ 49 million and $ 41 million at September 30, 2025 and December 31, 2024, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities

excludes cash of $ 24 million and $ 19 million at September 30, 2025 and December 31, 2024, respectively. BGE excludes cash of $ 6 million and $ 33 million at September 30, 2025 and December 31, 2024, respectively.

(b) The Level 3 balance consists of the current and noncurrent liability of $ 28 million and $ 100 million, respectively, at September 30, 2025 and $ 29 million and $ 103 million, respectively, at December 31, 2024 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 10 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL, and ACE


	At September 30, 2025								At December 31, 2024
PHI	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents (a)	$	56	$	—	$	—	$	56	$	93	$	—	$	—	$	93
Rabbi trust investments
Cash equivalents	97		—		—		97		92		—		—		92
Mutual funds	9		—		—		9		9		—		—		9
Fixed income	—		6		—		6		—		6		—		6
Life insurance contracts	—		22		21		43		—		23		21		44
Rabbi trust investments subtotal	106		28		21		155		101		29		21		151
Total assets	162		28		21		211		194		29		21		244
Liabilities
Deferred compensation obligation	—		( 10 )		—		( 10 )		—		( 12 )		—		( 12 )



Total liabilities	—		( 10 )		—		( 10 )		—		( 12 )		—		( 12 )
Total net assets	$	162	$	18	$	21	$	201	$	194	$	17	$	21	$	232


	Pepco								DPL								ACE
At September 30, 2025	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	$	2	$	—	$	—	$	2	$	—	$	—	$	—	$	—




Rabbi trust investments
Cash equivalents	97		—		—		97		—		—		—		—		—		—		—		—

Life insurance contracts	—		22		21		43		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	97		22		21		140		—		—		—		—		—		—		—		—
Total assets	119		22		21		162		2		—		—		2		—		—		—		—
Liabilities
Deferred compensation obligation	—		( 1 )		—		( 1 )		—		—		—		—		—		—		—		—



Total liabilities	—		( 1 )		—		( 1 )		—		—		—		—		—		—		—		—
Total net assets	$	119	$	21	$	21	$	161	$	2	$	—	$	—	$	2	$	—	$	—	$	—	$	—

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities


	Pepco								DPL								ACE
At December 31, 2024	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)	$	21	$	—	$	—	$	21	$	3	$	—	$	—	$	3	$	—	$	—	$	—	$	—
Rabbi trust investments
Cash equivalents	91		—		—		91		—		—		—		—		—		—		—		—


Life insurance contracts	—		23		21		44		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	91		23		21		135		—		—		—		—		—		—		—		—
Total assets	112		23		21		156		3		—		—		3		—		—		—		—
Liabilities
Deferred compensation obligation	—		( 1 )		—		( 1 )		—		—		—		—		—		—		—		—



Total liabilities	—		( 1 )		—		( 1 )		—		—		—		—		—		—		—		—
Total net assets	$	112	$	22	$	21	$	155	$	3	$	—	$	—	$	3	$	—	$	—	$	—	$	—

__________

(a) PHI excludes cash of $ 61 million and $ 70 million at September 30, 2025 and December 31, 2024, respectively, and restricted cash of $ 3 million and zero at September 30, 2025 and December 31, 2024. Pepco excludes cash of $ 25 million and $ 30 million at September 30, 2025 and December 31, 2024, respectively. DPL excludes cash of $ 6 million and $ 20 million at September 30, 2025 and December 31, 2024, respectively. ACE excludes cash of $ 25 million and $ 14 million at September 30, 2025 and December 31, 2024, respectively and restricted cash of $ 3 million and zero at September 30, 2025 and December 31, 2024, respectively.

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 nine months ended September 30, 2025 and 2024:



	Exelon		ComEd			PHI and Pepco
Three Months Ended September 30, 2025	Total		Commodity Derivatives			Life Insurance Contracts
Balance at June 30, 2025	$	( 112 )	$	( 135 )		$	22
Total realized / unrealized gains (losses)
Included in net income (a)	1		—			—


Included in regulatory assets/liabilities	7		7		(b)	—





Settlements	( 1 )		—			( 1 )


Balance at September 30, 2025	$	( 105 )	$	( 128 )	(c)	$	21
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2025	$	( 1 )	$	—		$	—

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities



	Exelon		ComEd			PHI and Pepco
Three Months Ended September 30, 2024	Total		Commodity Derivatives			Life Insurance Contracts
Balance at June 30, 2024	$	( 116 )	$	( 139 )		$	22
Total realized / unrealized gains (losses)
Included in net income (a)	—		—			—

Included in regulatory assets/liabilities	( 26 )		( 26 )		(b)	—





Settlements	( 1 )		—			( 1 )


Balance at September 30, 2024	$	( 143 )	$	( 165 )		$	21
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2024	$	—	$	—		$	—



	Exelon		ComEd			PHI and Pepco
Nine Months Ended September 30, 2025	Total		Commodity Derivatives			Life Insurance Contracts
Balance at December 31, 2024	$	( 110 )	$	( 132 )		$	21
Total realized / unrealized gains (losses)
Included in net income (a)	2		—			1


Included in regulatory assets/liabilities	4		4		(b)	—





Settlements	( 1 )		—			( 1 )


Balance at September 30, 2025	$	( 105 )	$	( 128 )	(c)	$	21
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2025	$	1	$	—		$	1



	Exelon		ComEd			PHI and Pepco
Nine Months Ended September 30, 2024	Total		Commodity Derivatives			Life Insurance Contracts
Balance at December 31, 2023	$	( 90 )	$	( 133 )		$	41
Total realized / unrealized gains (losses)
Included in net income (a)	1		—			2

Included in regulatory assets/liabilities	( 32 )		( 32 )		(b)	—





Settlements	( 22 )		—			( 22 )


Balance at September 30, 2024	$	( 143 )	$	( 165 )		$	21
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2024	$	2	$	—		$	2

__________

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

(b) Includes $ 1 million of increases in fair value and an increase for realized gains due to settlements of $ 6 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2025. Includes $ 31 million of decreases in fair value and an increase for realized gains due to settlements of $ 5 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2024. Includes $ 29 million of decreases in fair value and an increase for realized gains due to settlements of $ 33 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2025. Includes $ 60 million of decreases in fair value and an increase for realized gains due to settlements of $ 28 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2024.

(c) The balance of the current and noncurrent asset was effectively zero as of September 30, 2025. The balance consists of a current and noncurrent liability of $ 28 million and $ 100 million, respectively, as of September 30, 2025.

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities

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 September 30, 2025		Fair Value at December 31, 2024		Valuation Technique	Unobservable Input	2025 Range & Arithmetic Average				2024 Range & Arithmetic Average
Commodity derivatives	$	( 128 )	$	( 132 )	Discounted Cash Flow	Forward power price (a)	$ 29.88	-	$ 59.41	$ 41.89	$ 30.31	-	$ 59.88	$ 42.08

________

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

11. 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 2024 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 September 30, 2025:


Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments (a)	23		21		20		1		—

__________

(a) Remaining commitments extend through 2026 and include escrow funds, charitable contributions, and rate credits.

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Commitments and Contingencies

Commercial Commitments (All Registrants). The Registrants’ commercial commitments at September 30, 2025, representing commitments potentially triggered by future events were as follows:


			Expiration within
	Total		2025		2026		2027		2028		2029		2030 and beyond
Exelon
Letters of credit (a)	$	56	$	11	$	45	$	—	$	—	$	—	$	—
Surety bonds (b)	273		83		110		2		78		—		—
Financing trust guarantees (c)	378		—		—		—		78		—		300
Guaranteed lease residual values (d)	24		—		2		4		5		4		9
Total commercial commitments	$	731	$	94	$	157	$	6	$	161	$	4	$	309

ComEd
Letters of credit (a)	$	18	$	4	$	14	$	—	$	—	$	—	$	—
Surety bonds (b)	37		5		30		2		—		—		—
Financing trust guarantees (c)	200		—		—		—		—		—		200
Total commercial commitments	$	255	$	9	$	44	$	2	$	—	$	—	$	200

PECO
Letters of credit (a)	$	5	$	—	$	5	$	—	$	—	$	—	$	—
Surety bonds (b)	2		—		2		—		—		—		—
Financing trust guarantees (c)	178		—		—		—		78		—		100
Total commercial commitments	$	185	$	—	$	7	$	—	$	78	$	—	$	100

BGE
Letters of credit (a)	$	27	$	6	$	21	$	—	$	—	$	—	$	—
Surety bonds (b)	3		1		2		—		—		—		—
Total commercial commitments	$	30	$	7	$	23	$	—	$	—	$	—	$	—

PHI
Letters of credit (a)	$	4	$	—	$	4	$	—	$	—	$	—	$	—
Surety bonds (b)	172		73		21		—		78		—		—
Guaranteed lease residual values (d)	24		—		2		4		5		4		9
Total commercial commitments	$	200	$	73	$	27	$	4	$	83	$	4	$	9

Pepco
Letters of credit (a)	$	2	$	—	$	2	$	—	$	—	$	—	$	—
Surety bonds (b)	160		68		14		—		78		—		—
Guaranteed lease residual values (d)	8		—		1		1		2		1		3
Total commercial commitments	$	170	$	68	$	17	$	1	$	80	$	1	$	3

DPL
Letters of credit (a)	$	1	$	—	$	1	$	—	$	—	$	—	$	—
Surety bonds (b)	7		3		4		—		—		—		—
Guaranteed lease residual values (d)	9		—		—		2		2		2		3
Total commercial commitments	$	17	$	3	$	5	$	2	$	2	$	2	$	3

ACE
Letters of credit (a)	$	1	$	—	$	1	$	—	$	—	$	—	$	—
Surety bonds (b)	5		2		3		—		—		—		—
Guaranteed lease residual values (d)	7		—		1		1		1		1		3
Total commercial commitments	$	13	$	2	$	5	$	1	$	1	$	1	$	3

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Commitments and Contingencies

__________

(a) Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.

(b) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. Historically, payments under the guarantees have not been made and the likelihood of payments being required is remote.

(d) Represents the maximum potential obligation in the event 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 $ 55 million guaranteed by Exelon and PHI, of which $ 17 million, $ 21 million, and $ 17 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Environmental Remediation Matters

General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies, or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact 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 16 sites 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 2033.

• PECO has 6 sites 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 2030.

• BGE has 4 sites currently requiring some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2026.

• DPL has 1 site 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 performing 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.

During the third quarter of 2025, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. ComEd's study resulted in a $ 12 million increase to the environmental liability and related Regulatory asset, primarily due to increased costs resulting from inflation, adjustments to unit costs, and

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Commitments and Contingencies

changes in remediation plans. PECO's study resulted in a $ 2 million decrease to the environmental liability and related Regulatory asset, primarily due to decreased costs resulting from changes in remediation plans.

At September 30, 2025 and December 31, 2024, 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:


	September 30, 2025				December 31, 2024
	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	$	387	$	324	$	403	$	322
ComEd	290		290		285		284
PECO	25		24		29		28
BGE	13		10		13		10
PHI	57		—		75		—
Pepco	55		—		73		—
DPL	1		—		1		—
ACE	1		—		1		—

Benning Road Site (Exelon, PHI, and Pepco) . In September 2010, PHI received a letter from the 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 the DOEE approved on February 3, 2020. In October 2022, the 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. The landside FS was approved by the DOEE on March 15th, 2024, and the waterside FS was approved by the DOEE on December 16, 2024. The DOEE and Pepco entered into an addendum to the Benning Consent Decree pursuant to which Pepco has agreed to fund or perform the remedial actions to be selected by the DOEE for the landside and waterside areas. This addendum to the Benning Consent Decree was entered by the Court on February 27, 2024 and became effective on that date. Pepco drafted separate proposed plans for the landside and waterside areas, which were approved and issued by the DOEE for public comment on December 16, 2024 and September 4, 2025, respectively. The public comment period for the landside area closed on April 18, 2025 and the public comment period for the waterside area is scheduled to close on October 31, 2025. Pepco submitted a matrix of proposed responses to the public comments and a proposed Record of Decision (ROD) to the DOEE for the landside area on August 15, 2025. Following the close of the waterside area comment period, Pepco will submit a matrix of proposed responses to the public comments and a proposed ROD to the DOEE for the waterside area. The DOEE will issue RODs identifying the remedial actions determined to be necessary for the landside and waterside areas, which will be implemented by Pepco in accordance with the Benning Consent Decree.

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

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Commitments and Contingencies

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, the 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 riverwide 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 the DOEE’s contractor.

On September 30, 2020, the DOEE released its Interim ROD for the Anacostia River sediments. 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 the 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 the 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 agreeing to enter into settlement discussions. Pepco and the District entered into another consent decree (the “Anacostia River Consent Decree”) pursuant to which Pepco agreed to pay $ 47 million to resolve its liability to the District for all past costs to perform the riverwide RI/FS and all future costs to complete the work required by the Interim ROD. This amount was agreed to be paid in four equal annual installments beginning a year after the effective date of the Anacostia River Consent Decree. Pepco paid the first installment of $ 12 million on April 9, 2025. The funds were deposited into the DOEE’s Clean Land Fund for the District’s costs of the Interim ROD work. The Anacostia River Consent Decree caps Pepco’s liability for these costs and provides Pepco with the right to seek contributions from other PRPs. The Anacostia River Consent Decree was signed by the judge for the U.S. District Court for the District of Columbia and became effective on April 11, 2024. Exelon, PHI, and Pepco have accrued a liability for Pepco’s payment obligations under the Anacostia Consent Decree and management's best estimate of its share of any other future Anacostia River response costs. Pepco has 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 concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the early stage of the NRD process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process. Pepco has become aware, however, that the District is pursuing claims against other parties. Specifically, in January 2025, D.C. OAG filed a lawsuit against the United States seeking to declare the United States liable under CERCLA and the District of Columbia’s Brownfield Revitalization Act of 2000 and to recover the District’s response costs associated with its investigation and remediation of Anacostia River sediment contamination and for future NRDs. Pepco is not a party to this suit, but Pepco, the United States, and the District of Columbia have entered mediation discussions to resolve their respective claims against one another under CERCLA and the Brownfield Revitalization Act with respect to the river. The court has put the case on hold pending the outcome of the mediation.

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 Anacostia River Sediment Project was also assumed by this entity.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Commitments and Contingencies

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. Pepco entered into a Consent Order with the District of Columbia to resolve the alleged violations without any admission of liability. The Consent Order requires Pepco to pay a civil penalty of $ 10 million. In addition, Pepco has agreed to assess the environmental conditions at its Buzzard Point facility and conduct any remedial actions deemed necessary as a result of the assessment, and also to assess potential environmental impacts associated with the operation of its underground vaults. The Superior Court for the District of Columbia signed and entered the Consent Order, and it became effective on February 2, 2024. Pepco is proceeding through the multi-step environmental investigation and response as outlined in the consent order. Specifically, the DOEE approved Pepco's Preliminary Site Assessment in July 2025. In September 2025, Pepco timely submitted its work plan for the second stage, the Supplemental Investigation Plan. Pepco also submitted an environmental assessment to the DOEE of the vault system pursuant to the Consent Order in July 2024, and revisions in response to the DOEE's comments in May 2025 and September 2025. Exelon, PHI, and Pepco have accrued a liability for the projected costs for the required environmental assessments and remediation. In January 2025, Pepco paid the last installment of the civil penalty. Pepco has 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.

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. The Companies cooperated fully with the USAO and any government requests or inquiries. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation into its historical state legislative lobbying and related practices in Illinois. The agreement resolved the Department of Justice investigation into both ComEd and Exelon, which included a payment to the U.S. Treasury of $ 200 million, which was paid in November 2020. 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 against ComEd that had been deferred by the DPA.

Subsequent to Exelon announcing the receipt of the USAO subpoenas, various lawsuits were filed related to the subject of the subpoenas and the conduct described in the DPA. Several putative class actions were brought in federal and state court by ComEd customers. These actions were dismissed prior to discovery or trial and those dismissals were affirmed on appeal. A putative class action alleging misrepresentations and omissions in Exelon's SEC filings related to ComEd's lobbying activities and the related investigations was also brought in federal court against Exelon and ComEd, which was subsequently settled.

In addition, subsequent to Exelon announcing the receipt of the USAO subpoenas, several shareholders sent letters to the Exelon Board of Directors 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. Since that date, multiple parties have filed separate derivative lawsuits that were subsequently consolidated. On October 12, 2021, the parties filed an agreed motion to stay the litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The stay was extended several times. Through mediation efforts, a settlement of the derivative claims was reached 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 certain of the derivative shareholders. On June 16, 2023, the SLC filed a motion for preliminary approval of the settlement, attaching the Stipulation and Agreement of Settlement (Stipulation), which contained the terms of the proposed settlement. The proposed settlement terms include but

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Commitments and Contingencies

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. The non-settling shareholders objected to the settlement and opposed preliminary approval. On September 20, 2024, the court denied without prejudice the SLC’s motion for preliminary approval. The court’s order provided that if the SLC can substantiate or otherwise revise the attorneys’ fees aspect of the settlement, then the SLC could renew its motion for preliminary approval by October 21, 2024. On October 21, 2024, the SLC filed its second renewed motion for preliminary approval, and the Settling Shareholders filed a brief in support of the SLC's second renewed motion for preliminary approval. On November 20, 2024, the non-settling plaintiffs filed an opposition to the renewed motion for preliminary approval. On December 18, 2024, the SLC and Settling Shareholders filed replies in support of the renewed motion for preliminary approval.

Maryland Sales and Use Tax Refund Claim (Exelon, BGE, PHI, Pepco, and DPL). Maryland imposes a 6% sales and use tax on the purchase of most goods and services. BGE, Pepco, and DPL have filed or plan to file protective refund claims, totaling an estimated $ 100 million, treating electric transmission and distribution machinery and equipment as nontaxable pursuant to the manufacturing exemption available under the Maryland sales and use tax law. The Maryland Comptroller has initially denied the refund claim and litigation is pending.

On November 22, 2024, the Appellate Court of Maryland, in a case involving a regulated electric utility operating in Maryland, ruled the purchase of certain transmission and distribution equipment qualify for the sales tax manufacturing exemption. On December 20, 2024, the Maryland Attorney General, on behalf of the Maryland Comptroller, filed a motion for reconsideration with the Appellate Court of Maryland of its ruling. The motion for reconsideration was denied on February 3, 2025.

On February 18, 2025, the Maryland Attorney General, on behalf of the Maryland Comptroller, filed a petition with the Maryland Supreme Court requesting review of the Appellate Court of Maryland’s ruling. On April 24, 2025, the Maryland Supreme Court granted the petition to review the ruling. On October 1, 2025, the Maryland Supreme Court heard oral arguments in the case.

In the event transmission and distribution equipment is determined to be exempt, Exelon, BGE, PHI, Pepco, and DPL will record estimated receivables of $ 100 million, $ 65 million, $ 35 million, $ 25 million, and $ 10 million, respectively. The sales tax payments were primarily capitalized; therefore, the refund would be recorded as a reduction to PP&E included in rate base.

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.

12. Shareholders' Equity (Exelon)

At-the-Market Programs

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

Note 12 — Shareholders' Equity

On August 4, 2022, Exelon executed an equity distribution agreement (“2022 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 billion through August 3, 2025. On May 2, 2025, Exelon executed an additional equity distribution agreement ("2025 Equity Distribution Agreement" and, together with the August 4, 2022 Equity Distribution Agreement, "Equity Distribution Agreements"), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $ 2.5 billion through May 2, 2028. The 2025 Equity Distribution Agreement replaced the 2022 Equity Distribution Agreement. Exelon has no obligation to offer or sell any shares of Common stock under the 2025 Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the 2025 Equity Distribution Agreement.

During the first quarter of 2025, Exelon issued approximately 4.0 million shares of Common stock at an average net price of $ 42.98 per share. The net proceeds from the issuance were $ 173 million, which were used for general corporate purposes.

In addition, in the first quarter of 2025, Exelon entered into forward sale agreements for 5.7 million shares of Common stock, at a weighted-average net forward price of $ 43.24 per share. The forward sale agreements require Exelon to, at its election prior to December 15, 2025, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements.

In the second quarter of 2025, Exelon entered into forward sale agreements for 6.2 million shares and 3.6 million shares of Common stock at weighted-average net forward prices of $ 43.51 and $ 43.17 per share, respectively. The forward sale agreements require Exelon to, at its election prior to December 15, 2025 and November 16, 2026, respectively, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements.

In the third quarter of 2025, Exelon entered into forward sale agreements for 11.5 million shares at a weighted-average net forward price of $ 43.73 per share. The forward sale agreements require Exelon to, at its election prior to December 15, 2026 either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements.

No amounts have been or will be recorded on Exelon's balance sheet with respect to the equity offerings until the equity forward sale agreements have been settled. Each initial forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the nine months ended September 30, 2025, approximately 26.7 million shares under the forward sale agreements were not included in the calculation of diluted earnings per share because their effect would have been antidilutive.

Inclusive of the impact of the forward sale agreements, $ 1.6 billion of Common stock remained available for sale pursuant to the ATM program as of September 30, 2025.

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 13 — Changes in Accumulated Other Comprehensive Income

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

The following table presents changes in Exelon's AOCI, net of tax, by component:


Three Months Ended September 30, 2025	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items (a)		Total
Balance at June 30, 2025	$	31	$	( 749 )	$	( 718 )
OCI before reclassifications	( 1 )		—		( 1 )
Amounts reclassified from AOCI	( 1 )		5		4
Net current-period OCI	( 2 )		5		3
Balance at September 30, 2025	$	29	$	( 744 )	$	( 715 )


Three Months Ended September 30, 2024	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items (a)		Total
Balance at June 30, 2024	$	27	$	( 739 )	$	( 712 )
OCI before reclassifications	( 28 )		—		( 28 )
Amounts reclassified from AOCI	( 1 )		5		4
Net current-period OCI	( 29 )		5		( 24 )
Balance at September 30, 2024	$	( 2 )	$	( 734 )	$	( 736 )


Nine Months Ended September 30, 2025	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items (a)		Total
December 31, 2024	$	45	$	( 765 )	$	( 720 )
OCI before reclassifications	( 11 )		5		( 6 )
Amounts reclassified from AOCI	( 5 )		16		11
Net current-period OCI	$	( 16 )	$	21	$	5
Balance at September 30, 2025	$	29	$	( 744 )	$	( 715 )


Nine Months Ended September 30, 2024	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items (a)		Total
Balance at December 31, 2023	$	( 3 )	$	( 723 )	$	( 726 )
OCI before reclassifications	4		( 26 )		( 22 )
Amounts reclassified from AOCI	( 3 )		15		12
Net current-period OCI	$	1	$	( 11 )	$	( 10 )
Balance at September 30, 2024	$	( 2 )	$	( 734 )	$	( 736 )

__________

(a) This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits of the 2024 Form 10-K and Note 7 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 13 — Changes in Accumulated Other Comprehensive Income

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Pension and non-pension postretirement benefit plans:

Actuarial losses reclassified to periodic benefit cost	$	( 2 )	$	( 2 )	$	( 6 )	$	( 6 )
Pension and non-pension postretirement benefit plans valuation adjustments	—		—		( 2 )		8
Unrealized gains on cash flow hedges	2		10		4		—

14. Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

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


	Taxes other than income taxes
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2025
Utility taxes (a)	$	269	$	85	$	58	$	27	$	99	$	91	$	7	$	1
Property	119		9		6		61		43		29		13		1
Payroll	34		9		4		5		8		2		1		1

Three Months Ended September 30, 2024
Utility taxes (a)	$	248	$	80	$	51	$	25	$	92	$	84	$	7	$	1
Property	111		7		5		57		41		28		12		1
Payroll	33		9		4		5		7		2		1		—

Nine Months Ended September 30, 2025
Utility taxes (a)	$	765	$	244	$	156	$	85	$	280	$	255	$	22	$	3
Property	341		27		15		175		123		84		37		2
Payroll	101		26		14		14		22		5		3		2

Nine Months Ended September 30, 2024
Utility taxes (a)	$	695	$	229	$	134	$	78	$	254	$	230	$	21	$	3
Property	323		25		14		164		119		81		35		2
Payroll	100		27		13		14		22		6		3		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.

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 14 — Supplemental Financial Information


	Other, net
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2025
AFUDC — Equity	$	49	$	19	$	9	$	11	$	10	$	8	$	1	$	1
Non-service net periodic benefit cost	( 13 )		—		—		—		—		—		—		—

Three Months Ended September 30, 2024
AFUDC — Equity	$	38	$	13	$	7	$	5	$	12	$	8	$	3	$	1
Non-service net periodic benefit cost	( 13 )		—		—		—		—		—		—		—

Nine Months Ended September 30, 2025
AFUDC — Equity	$	130	$	45	$	26	$	29	$	30	$	23	$	4	$	3
Non-service net periodic benefit cost	( 39 )		—		—		—		—		—		—		—

Nine Months Ended September 30, 2024
AFUDC — Equity	$	116	$	32	$	24	$	18	$	42	$	32	$	9	$	1
Non-service net periodic benefit cost	( 29 )		—		—		—		—		—		—		—

Supplemental Cash Flow Information

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


	Depreciation, amortization, and accretion
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL			ACE
Nine Months Ended September 30, 2025
Property, plant, and equipment (a)	$	2,270	$	915	$	333	$	375	$	606	$	268	$	169	`	$	166
Amortization of regulatory assets and liabilities, net (a)	444		247		3		98		95		53		20			22
Amortization of intangible assets, net (a)	3		—		—		—		—		—		—			—


ARO accretion (b)	2		—		—		—		2		1		—			—
Total depreciation, amortization and accretion	$	2,719	$	1,162	$	336	$	473	$	703	$	322	$	189		$	188

Nine Months Ended September 30, 2024
Property, plant, and equipment (a)	$	2,168	$	869	$	308	$	369	$	581	$	249	$	162		$	158
Amortization of regulatory assets and liabilities, net (a)	507		255		10		105		135		58		21			56
Amortization of intangible assets, net (a)	6		—		—		—		—		—		—			—


ARO accretion (b)	2		—		—		—		—		—		—			—
Total depreciation and amortization	$	2,683	$	1,124	$	318	$	474	$	716	$	307	$	183		$	214

__________

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

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

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

Note 14 — Supplemental Financial Information


	Other non-cash operating activities
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2025
Pension and OPEB costs	$	204	$	64	$	5	$	46	$	72	$	26	$	12	$	10
Allowance for credit losses	202		41		75		20		66		29		13		24


True-up adjustments to decoupling mechanisms and formula rates (a)	627		525		6		63		33		19		10		4





Amortization of operating ROU asset	22		—		—		5		13		4		4		2


AFUDC — Equity	( 130 )		( 45 )		( 26 )		( 29 )		( 30 )		( 23 )		( 4 )		( 3 )

Nine Months Ended September 30, 2024
Pension and OPEB costs (benefit)	$	181	$	53	$	( 1 )	$	45	$	71	$	24	$	11	$	10
Allowance for credit losses	170		17		79		23		51		25		7		19


True-up adjustments to decoupling mechanisms and formula rates (a)	49		100		( 3 )		( 28 )		( 20 )		( 42 )		7		15





Amortization of operating ROU asset	28		—		—		5		19		4		6		2


AFUDC — Equity	( 116 )		( 32 )		( 24 )		( 18 )		( 42 )		( 32 )		( 9 )		( 1 )

__________

(a) For ComEd, reflects the true-up adjustments in Regulatory assets and liabilities associated with its distribution MRP and 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 2024 Form 10-K for additional 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.

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

Note 14 — Supplemental Financial Information


	Cash, cash equivalents, and restricted cash
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at September 30, 2025
Cash and cash equivalents	$	1,533	$	405	$	364	$	663	$	93	$	25	$	6	$	25
Restricted cash and cash equivalents	516		453		—		2		27		22		2		3
Restricted cash included in Other deferred debits and other assets	49		49		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	2,098	$	907	$	364	$	665	$	120	$	47	$	8	$	28

Balance at December 31, 2024
Cash and cash equivalents	$	357	$	105	$	48	$	33	$	139	$	30	$	21	$	14
Restricted cash and cash equivalents	541		486		—		1		24		21		2		—
Restricted cash included in Other deferred debits and other assets	41		41		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	939	$	632	$	48	$	34	$	163	$	51	$	23	$	14

Balance at September 30, 2024
Cash and cash equivalents	$	616	$	109	$	28	$	330	$	100	$	20	$	8	$	17
Restricted cash and cash equivalents	552		481		9		—		22		20		2		—
Restricted cash included in Other deferred debits and other assets	65		65		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,233	$	655	$	37	$	330	$	122	$	40	$	10	$	17

Balance at December 31, 2023
Cash and cash equivalents	$	445	$	110	$	42	$	47	$	180	$	48	$	16	$	21
Restricted cash and cash equivalents	482		402		9		1		24		24		—		—
Restricted cash included in Other deferred debits and other assets	174		174		—		—		—		—		—		—

Total cash, restricted cash, and cash equivalents	$	1,101	$	686	$	51	$	48	$	204	$	72	$	16	$	21

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2024 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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(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Supplemental Financial Information


	Accrued expenses
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at September 30, 2025
Compensation-related accruals (a)	$	584	$	179	$	74	$	73	$	105	$	29	$	20	$	13
Taxes accrued	283		160		13		96		116		82		21		7
Interest accrued	458		106		59		91		86		38		28		18


Balance at December 31, 2024
Compensation-related accruals (a)	$	679	$	197	$	87	$	88	$	132	$	38	$	26	$	18
Taxes accrued	217		96		13		34		110		92		11		11
Interest accrued	468		150		60		50		83		44		16		18

__________

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

15. Related Party Transactions (All Registrants)

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 September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024		2025		2024		2025		2024
Exelon
BSC									$	156	$	141	$	478	$	458
PHISCO									29		27		83		85
ComEd
BSC	$	95	$	102	$	296	$	306	63		55		186		189
PECO
BSC	58		61		178		180		24		23		79		81
BGE
BSC	60		61		185		182		28		25		92		74
PHI
BSC	44		46		144		145		41		38		121		114
PHISCO	—		—		—		—		29		27		83		85
Pepco
BSC	30		29		93		92		18		16		52		51
PHISCO	29		28		91		94		14		12		36		36

DPL
BSC	19		19		58		58		12		11		36		36
PHISCO	24		24		75		75		8		8		25		25

ACE
BSC	15		16		47		48		10		9		28		24
PHISCO	22		23		69		71		7		7		22		24

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Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 15 — Related Party Transactions

Current Receivables from/Payables to Affiliates

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

September 30, 2025


				Receivables from affiliates:
	Payables to affiliates:			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
ComEd					$	—		$	—		$	—		$	—		$	—		$	60		$	—		$	1		$	61
PECO		$	—					—			—			—			—			30			—			5			35
BGE		—			—						—			—			—			33			—			—			33
PHI		—			—			1			—			—			—			5			—			10			16
Pepco		—			—			—						—			—			17			15			1			33
DPL		—			—			—			—						—			11			11			1			23
ACE		—			—			—			—			—						9			9			—			18
Other		4			2			—			1			1			11			—			—						19
Total		$	4		$	2		$	1		$	1		$	1		$	11		$	165		$	35		$	18		$	238

December 31, 2024


				Receivables from affiliates:
	Payables to affiliates:			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
ComEd					$	—		$	—		$	—		$	—		$	—		$	67		$	—		$	10		$	77
PECO		$	—					—			—			—			—			37			—			4			41
BGE		—			—						—			—			—			47			—			1			48
PHI		—			—			—			—			—			—			7			1			10			18
Pepco		—			—			—						—			—			21			15			1			37
DPL		—			—			—			—						—			14			11			1			26
ACE		—			—			—			—			—						11			10			1			22
Other		4			—			—			1			—			7			—			—						12
Total		$	4		$	—		$	—		$	1		$	—		$	7		$	204		$	37		$	28		$	281

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:


	September 30, 2025						December 31, 2024
	Exelon		ComEd		PECO		Exelon		ComEd		PECO
ComEd Financing III	$	206	$	206	$	—	$	206	$	206	$	—
PECO Trust III	81		—		81		81		—		81
PECO Trust IV	103		—		103		103		—		103
Total	$	390	$	206	$	184	$	390	$	206	$	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 its six reportable segments: ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.

Exelon’s consolidated financial information includes the results of its 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 by Registrant for the three and nine months ended September 30, 2025 compared to the same period in 2024. For additional information regarding the financial results for the three and nine months ended September 30, 2025 and 2024, see the discussions of Results of Operations by Registrant.


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2025		2024				2025		2024
Exelon	$	875	$	707	$	168	$	2,174	$	1,813	$	361
ComEd	373		360		13		903		823		80
PECO	250		117		133		652		356		296
BGE	82		45		37		398		353		45
PHI	291		278		13		628		603		25
Pepco	156		140		16		337		323		14
DPL	55		55		—		163		156		7
ACE	82		83		(1)		138		133		5
Other (a)	(121)		(93)		(28)		(407)		(322)		(85)

__________

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

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net income attributable to common shareholders increased by $168 million and diluted earnings per average common share increased to $0.86 in 2025 from $0.70 in 2024 primarily due to:

• Favorable impacts of rates at ComEd, PECO, BGE, and PHI;

• Lower storm costs at PECO, due to deferral of extraordinary February and June storm costs;

• Timing of income tax expenses at PECO;

• Higher return on regulatory assets at ComEd;

• Higher AFUDC at ComEd; and

• Lower storm costs and credit loss expense at BGE.

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The increases were partially offset by:

• Timing of distribution earnings at ComEd;

• Higher depreciation expense at PECO; and

• Higher interest expense at PHI and Exelon Corporate.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net income attributable to common shareholders increased by $361 million and diluted earnings per average common share increased to $2.15 in 2025 from $1.81 in 2024 primarily due to:

• Favorable impacts of rates at ComEd, PECO, BGE and PHI;

• Timing of income tax expenses at PECO;

• Less unfavorable weather at PECO;

• Lower storm costs at PECO and BGE;

• Higher return on regulatory assets at ComEd;

• Timing of distribution earnings at ComEd; and

• Higher AFUDC at ComEd.

The increases were partially offset by:

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

• Customer Relief Fund contribution at Exelon Corporate;

• Higher depreciation expense at PECO and PHI;

• Lower transmission peak load due to lower energy demand at ComEd;

• Lower impacts of the Maryland multi-year plan reconciliations at PHI; and

• Lower AFUDC at PHI.

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-over-year operating results and provide an indication of Exelon’s baseline operating performance excluding items not considered by management to be directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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The following table provides a reconciliation between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2025 compared to the same period in 2024:



	Three Months Ended September 30,
	2025				2024
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net income attributable to common shareholders	$	875	$	0.86	$	707	$	0.70


Asset retirement obligation (net of taxes of $0 and $0, respectively)	(1)		—		—		—






Cost management charge (net of taxes of $0) (a)	—		—		1		—

Adjusted (non-GAAP) operating earnings	$	874	$	0.86	$	708	$	0.71


	Nine Months Ended September 30,
	2025				2024
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net income attributable to common shareholders	$	2,174	$	2.15	$	1,813	$	1.81


Asset retirement obligation (net of taxes of $0 and $0, respectively)	(1)		—		—		—


Change in FERC audit liability (net of taxes of $1 and $13, respectively)	2		—		42		0.04

Cost management charge (net of taxes of $0 and $3, respectively) (a)	(1)		—		10		0.01
Income tax-related adjustments (entire amount represents tax expense) (b)	1		—		—		—
Regulatory matters (net of taxes of $7) (c)	22		0.02		—		—
Change in environmental liabilities (net of taxes of $0)	—		—		(1)		—
Adjusted (non-GAAP) operating earnings	$	2,198	$	2.17	$	1,865	$	1.86

__________

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income attributable to common shareholders 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 2025 and 2024 ranged from 24.0% to 29.0%.

(a) Primarily represents severance and reorganization costs related to cost management.

(b) Reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.

Significant 2025 Transactions and Developments

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 2025. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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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	January 17, 2023	Electric	$	1,487	$	1,045	8.905%	December 19, 2024	January 1, 2024
	April 26, 2024 (amended on September 11, 2024)	Electric	$	624	$	623	9.89%	October 31, 2024	January 1, 2025
PECO - Pennsylvania	March 28, 2024	Electric	$	464	$	354	N/A	December 12, 2024	January 1, 2025
		Natural Gas	$	111	$	78
BGE - Maryland	February 17, 2023	Electric	$	313	$	179	9.50%	December 14, 2023	January 1, 2024
		Natural Gas	$	289	$	229	9.45%
Pepco - District of Columbia	April 13, 2023 (amended February 27, 2024)	Electric	$	186	$	123	9.50%	November 26, 2024	January 1, 2025
Pepco - Maryland	May 16, 2023 (amended February 23, 2024)	Electric	$	111	$	45	9.50%	June 10, 2024	April 1, 2024
DPL - Maryland	May 19, 2022	Electric	$	38	$	29	9.60%	December 14, 2022	January 1, 2023
DPL - Delaware	December 15, 2022 (amended September 29, 2023)	Electric	$	39	$	28	9.60%	April 18, 2024	July 15, 2023
ACE - New Jersey	February 15, 2023 (amended August 21, 2023)	Electric	$	92	$	45	9.60%	November 17, 2023	December 1, 2023

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Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

Pepco - Maryland

October 14, 2025

Electric

133

10.50%

Third quarter of 2026

DPL - Delaware

September 20, 2024 (amended September 5, 2025)

Natural Gas

10.65%

First quarter of 2026

ACE - New Jersey

November 21, 2024

Electric

109

10.70%

Fourth quarter of 2025

Transmission Formula Rates

For 2025, the following total increases/(decreases) were included in the Utility Registrant's electric transmission formula rate updates. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.


Registrant	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation Increase (Decrease)		Total Revenue Requirement Increase (Decrease)		Allowed Return on Rate Base		Allowed ROE
ComEd	$	78	$	49	$	127	8.13	%	11.50	%
PECO	$	9	$	13	$	22	7.54	%	10.35	%
BGE	$	21	$	21	$	35	7.53	%	10.50	%
Pepco	$	35	$	16	$	51	7.71	%	10.50	%
DPL	$	32	$	(9)	$	23	7.48	%	10.50	%
ACE	$	(11)	$	(46)	$	(57)	7.16	%	10.50	%

ComEd's FERC Audit

The Utility Registrants are subject to periodic audits and investigations 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 period extended back to January 1, 2017.

On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The existing loss estimate was reflected in Exelon and ComEd's financial statements as of December 31, 2024. ComEd and FERC staff jointly filed the settlement agreement with FERC for approval on February 11, 2025. The settlement was approved by FERC on April 4, 2025.

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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 2024 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 2024 Form 10-K, and Note 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.

Allocation of Income Taxes to Regulated Utilities (All Registrants)

In Q2 2024, the IRS issued a series of PLRs, to another taxpayer, providing guidance with respect to the application of the tax normalization rules to the allocation of consolidated tax benefits among the members of a consolidated group associated with NOLC for ratemaking purposes. The rulings provide that for ratemaking purposes the tax benefit of NOLC should be reflected on a separate company basis not taking into consideration the utilization of losses by other affiliates. A PLR issued to another taxpayer may not be relied on as precedent.

The Utility Registrants, except for PECO, filed PLR requests with the IRS confirming the treatment of the NOLC for ratemaking purposes. The Utility Registrants will record the impact, if any, upon receiving the PLR from the IRS.

Legislative and Regulatory Developments

Infrastructure Investment and Jobs Act

On November 15, 2021, the $1.2 trillion IIJA was signed 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. The Registrants continue to evaluate programs under the legislation and consider 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.

On January 20, 2025, the Unleashing American Energy Order was issued as a Presidential Executive Order, which required an immediate pause in the disbursement of funds appropriated through the IRA and IIJA pending DOE review. In October 2025, Exelon, ComEd, and BGE received termination notifications from the DOE for their Renewable-Aware Distribution Operations, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, and Baltimore Interconnection Readiness & Deployment of Storage (BIRDS) awards, respectively. There are no material financial statement impacts as a result of the DOE terminations. Exelon, ComEd, and BGE will continue to evaluate whether to move forward with these projects.

Next Generation Energy Act (Exelon, BGE, PHI, Pepco, and DPL)

On May 20, 2025, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including affirming that the MDPSC may approve the use of multi-year rate plans that demonstrate customer benefits, among other things. It also prohibits utilities from filing after January 1, 2025, for the reconciliation of actuals costs and revenues to amounts approved within the multi-year plans. In the second quarter of 2025, BGE derecognized Regulatory assets of $10 million and Regulatory liabilities of $3 million for multi-year plan reconciliations that will no longer be filed. DPL also derecognized Regulatory liabilities of $0.4 million during the second quarter of 2025 for multi-year reconciliations yet to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings.

Summer Rate Mitigation (Exelon, BGE, PHI, Pepco, DPL, and ACE).

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As part of the passing of the Next Generation Energy Act by the Maryland General Assembly, the MDPSC issued an order on June 26, 2025, to implement the Legislative Energy Relief Refund program under which bill credits will be distributed to residential customers based on their consumption of electricity supply that is subject to the renewable energy portfolio standard. On July 24, 2025, the MDPSC issued an order accepting BGE, Pepco, and DPL's proposal for the implementation of the program. As a result, BGE, Pepco, and DPL received approximately $49 million, $21 million, and $8 million, respectively, from the MDPSC on August 6, 2025. These amounts were used to reduce residential customer accounts receivable balances within the third quarter. An additional disbursement from the state of Maryland is expected in the first quarter of 2026, which will also be used to reduce residential customer receivables upon receipt.

In response to significant increases in electric supply costs, on April 23, 2025, the NJBPU issued an order directing the State's electric public utilities to file petitions proposing distribution side measures to mitigate residential customer bill impacts during summer months. As a result, on June 18, 2025, the NJBPU approved a stipulation of settlement for ACE to issue a bill credit of $30 per residential customer for the months of July and August 2025, which was deferred to a Regulatory asset. The amounts will subsequently be collected from September 2025 through February 2026 at a flat rate of $10 per residential customer. The bill credit and subsequent collections will not be subject to carrying costs.

In an effort to further reduce the burden of increased electric supply costs, on August 13, 2025, the NJBPU issued an order to establish the RUBC, which will be funded by the NJBPU. The program will provide a $50 bill credit per eligible residential customer for the months of September and October 2025. ACE received $51 million from the NJBPU on September 25, 2025, which was recognized as a Regulatory liability. ACE subsequently issued $25 million in bill credits to residential customers in September 2025 reducing the Regulatory liability to $26 million as of September 30, 2025. The remaining funds were disbursed in October 2025.

One Big Beautiful Bill Act (All Registrants)

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 September 30, 2025, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2024. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2024 Form 10-K for further information.

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Results of Operations by Registrant

Results of Operations — ComEd


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				(Unfavorable) Favorable Variance
	2025		2024				2025		2024
Operating revenues	$	2,275	$	2,229	$	46	$	6,176	$	6,403	$	(227)
Operating expenses
Purchased power	806		835		29		2,044		2,504		460
Operating and maintenance	409		410		1		1,254		1,277		23
Depreciation and amortization	395		387		(8)		1,162		1,124		(38)
Taxes other than income taxes	107		99		(8)		303		287		(16)
Total operating expenses	1,717		1,731		14		4,763		5,192		429
Gain on sales of assets	—		—		—		—		5		(5)
Operating income	558		498		60		1,413		1,216		197
Other income and (deductions)
Interest expense, net	(135)		(128)		(7)		(395)		(374)		(21)
Other, net	33		26		7		86		66		20
Total other income and (deductions)	(102)		(102)		—		(309)		(308)		(1)
Income before income taxes	456		396		60		1,104		908		196
Income taxes	83		36		(47)		201		85		(116)
Net income	$	373	$	360	$	13	$	903	$	823	$	80

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net Income increased by $13 million as compared to the same period in 2024 primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers, higher return on regulatory assets due to an increase in asset balances, and higher AFUDC, partially offset by the timing of distribution earnings.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net income increased by $80 million as compared to the same period in 2024, primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers, higher return on regulatory assets due to an increase in asset balances, higher AFUDC, and timing of distribution earnings, partially offset by lower transmission peak load.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		Increase (Decrease)
Distribution	$	85	$	200
Transmission	3		(15)
Energy efficiency	9		25
Other	(30)		(17)
	67		193
Regulatory required programs	(21)		(420)
Total increase (decrease)	$	46	$	(227)

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

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ComEd

Distribution Revenue. Starting in 2024, distribution revenues are under a MRP. The MRP requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenues increased for the three months ended September 30, 2025 as compared to the same period in 2024, primarily due to higher fully recoverable costs, higher rate base, and higher return on regulatory assets. Electric distribution revenues increased for the nine months ended September 30, 2025 as compared to the same period in 2024, primarily due to higher fully recoverable costs, higher rate base, higher return on regulatory assets, and differences in the timing of distribution earnings.

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. Transmission revenues increased for the three months ended September 30, 2025 compared to the same period in 2024, primarily due to higher fully recoverable costs and higher rate base. Transmission revenues decreased for the nine months ended September 30, 2025 as compared to the same period in 2024, primarily due to lower transmission peak load, partially offset by higher fully recoverable costs and the impacts of higher rate base.

Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenues increased for the three and nine months ended September 30, 2025 as compared to the same periods in 2024, 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 revenues decreased for the three and nine months ended September 30, 2025 as compared to the same periods in 2024, which primarily reflects decreased 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. ETAC is a retail customer surcharge collected 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 taxes. 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 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

The decrease in Purchased power expense of $29 million and $460 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024 is offset in Operating revenues as part of regulatory required programs.

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ComEd

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


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		(Decrease) Increase

Labor, other benefits, contracting, and materials	$	3	$	(14)
Storm-related costs	(2)		(5)
BSC costs	(7)		(10)
Pension and non-pension postretirement benefits expense	1		4



Other (a)	9		(33)
	4		(58)
Regulatory required programs (b)	(5)		35
Total decrease	$	(1)	$	(23)

__________

(a) Primarily reflects the reclassification and increase of the FERC audit liability and a decrease in credit loss expense during the nine months ended September 30, 2024. See Note 2 - Regulatory Matters for additional information regarding the FERC audit liability.

(b) 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 September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization (a)	$	12	$	46
Regulatory asset amortization	(4)		(8)

Total increase	$	8	$	38

__________

(a) Reflects ongoing capital expenditures.

Interest expense, net increased $7 million and $21 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to an increase in outstanding debt.

Other , net increased $7 million and $20 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to higher AFUDC equity.

Effective income tax rat es were 18.2% and 9.1% for the three months ended September 30, 2025 and 2024, respectively, and 18.2% and 9.4% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — 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 September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2025		2024				2025		2024
Operating revenues	$	1,180	$	1,030	$	150	$	3,513	$	2,975	$	538
Operating expenses
Purchased power and fuel	446		386		(60)		1,288		1,113		(175)
Operating and maintenance	241		313		72		872		876		4
Depreciation and amortization	115		108		(7)		336		318		(18)
Taxes other than income taxes	69		61		(8)		183		164		(19)
Total operating expenses	871		868		(3)		2,679		2,471		(208)
Gain on sales of assets	—		—		—		—		4		(4)
Operating income	309		162		147		834		508		326
Other income and (deductions)
Interest expense, net	(65)		(58)		(7)		(188)		(170)		(18)
Other, net	11		9		2		29		27		2
Total other income and (deductions)	(54)		(49)		(5)		(159)		(143)		(16)
Income before income taxes	255		113		142		675		365		310
Income taxes	5		(4)		(9)		23		9		(14)


Net income	$	250	$	117	$	133	$	652	$	356	$	296

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net income increased by $133 million due to an increase in revenue as a result of electric and gas distribution rates, decrease in storm costs due to deferral of extraordinary February and June storm costs in the third quarter of 2025, and tax repairs deduction related to storms, some of which is timing, partially offset by an increase in depreciation expense.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net income increased by $296 million due to an increase in revenue as a result of electric and gas distribution rates, coupled with less unfavorable weather relative to the same period last year, decrease in storm costs due to deferral of extraordinary February and June storm costs in the third quarter of 2025 and lower storm costs relative to the same period last year, and tax repairs deduction related to storms, some of which is timing, partially offset by an increase in depreciation expense and interest expense.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2025						Nine Months Ended September 30, 2025
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	1	$	—	$	1	$	18	$	18	$	36
Volume	(11)		—		(11)		(17)		2		(15)
Pricing	99		8		107		263		65		328
Transmission	—		—		—		(3)		—		(3)
Other	—		—		—		10		5		15
	89		8		97		271		90		361
Regulatory required programs	48		5		53		124		53		177
Total increase	$	137	$	13	$	150	$	395	$	143	$	538

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

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demand. During the three months ended September 30, 2025 compared to the same period in 2024, Operating revenues related to weather remained relatively consistent. During the nine months ended September 30, 2025 compared to the same period in 2024, Operating revenues related to weather increased due to less unfavorable weather conditions in PECO's service territory.

Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and nine months ended September 30, 2025 compared to the same period in 2024 and normal weather consisted of the following:


	Three Months Ended September 30,			% Change
PECO Service Territory	2025	2024	Normal	2025 vs. 2024		2025 vs. Normal
Heating Degree-Days	—	1	20	(100.0)	%	(100.0)	%
Cooling Degree-Days	1,095	1,062	1,035	3.1	%	5.8	%
	Nine Months Ended September 30,			% Change
	2025	2024	Normal	2025 vs. 2024		2025 vs. Normal
Heating Degree-Days	2,684	2,441	2,827	10.0	%	(5.1)	%
Cooling Degree-Days	1,521	1,599	1,422	(4.9)	%	7.0	%

Volume. Electric volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2025 compared to the same period in 2024, decreased due to customer load. Natural gas volume for the three and nine months ended September 30, 2025 compared to the same period in 2024, remained relatively consistent.


Electric Retail Deliveries to Customers (in GWhs)	Three Months Ended September 30,		% Change		Weather - Normal % Change (b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change (b)
	2025	2024					2025	2024
Residential	4,063	4,146	(2.0)	%	(2.1)	%	10,952	10,897	0.5	%	(1.5)	%
Small commercial & industrial	2,057	2,129	(3.4)	%	(2.0)	%	5,835	5,876	(0.7)	%	(2.0)	%
Large commercial & industrial	3,731	3,768	(1.0)	%	(2.3)	%	10,470	10,531	(0.6)	%	(1.4)	%
Public authorities & electric railroads	159	156	1.9	%	1.7	%	511	470	8.7	%	8.6	%
Total electric retail deliveries (a)	10,010	10,199	(1.9)	%	(2.1)	%	27,768	27,774	—	%	(1.4)	%


	At September 30,
Number of Electric Customers	2025	2024
Residential	1,539,345	1,529,205
Small commercial & industrial	154,955	155,126
Large commercial & industrial	3,159	3,156
Public authorities & electric railroads	10,343	10,716
Total	1,707,802	1,698,203

__________

(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.

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Natural Gas Deliveries to Customers (in mmcf)	Three Months Ended September 30,		% Change		Weather - Normal % Change (b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change (b)
	2025	2024					2025	2024
Residential	2,064	2,359	(12.5)	%	(12.1)	%	28,469	25,779	10.4	%	(0.5)	%
Small commercial & industrial	2,243	1,933	16.0	%	17.5	%	16,046	14,742	8.8	%	1.8	%
Large commercial & industrial	—	1	(100.0)	%	(9.8)	%	14	17	(17.6)	%	(3.8)	%
Transportation	5,081	5,232	(2.9)	%	(2.6)	%	17,759	17,248	3.0	%	0.4	%
Total natural gas retail deliveries (a)	9,388	9,525	(1.4)	%	(1.2)	%	62,288	57,786	7.8	%	0.3	%


	At September 30,
Number of Natural Gas Customers	2025	2024
Residential	510,166	506,476
Small commercial & industrial	44,603	44,682
Large commercial & industrial	7	7
Transportation	619	643
Total	555,395	551,808

__________

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

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

Pricing for the three and nine months ended September 30, 2025 compared to the same period in 2024 increased primarily due to electric and 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. Transmission revenue for the three and nine months ended September 30, 2025 compared to the same period in 2024 remained relatively consistent.

Other Revenue primarily includes revenue related to late payment charges. Other revenue for the three months ended September 30, 2025 compared to the same period in 2024 remained relatively consistent. Other revenue for the nine months ended September 30, 2025 compared to the same period in 2024 increased primarily due to revenue related to late payment charges.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, TSC, and the GSA. The riders are designed to provide full and current cost recovery, and in some cases, 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 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

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The increase of $60 million and increase of $175 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, 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 September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting and materials	$	18	$	32
Pension and non-pension postretirement benefit expense	1		3
BSC costs	(3)		(1)
Credit loss expense	(7)		(3)
Storm-related costs (a)	(63)		(29)
Other	(7)		(7)
	(61)		(5)
Regulatory required programs	(11)		1
Total decrease	$	(72)	$	(4)

__________

(a) Decrease primarily due to deferral of extraordinary February and June storm costs of $53 million in the third quarter of 2025.

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


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization (a)	$	10	$	26
Regulatory asset amortization	(3)		(8)

Total increase	$	7	$	18

__________

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

Taxes other than income taxes increased by $8 million and increased by $19 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, primarily due to higher Pennsylvania gross receipts tax.

Interest expense, net increased $7 million and increased $18 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, primarily due to an increase in interest rates and the issuance of debt in the third quarter of 2025.

Effective income tax rates were 2.0% and (3.5)% for the three months ended September 30, 2025 and 2024, respectively, 3.4% and 2.5% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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Results of Operations — BGE


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2025		2024				2025		2024
Operating revenues	$	1,209	$	1,044	$	165	$	3,791	$	3,268	$	523
Operating expenses
Purchased power and fuel	568		420		(148)		1,584		1,228		(356)
Operating and maintenance	239		281		42		807		795		(12)
Depreciation and amortization	155		162		7		473		474		1
Taxes other than income taxes	93		86		(7)		273		254		(19)
Total operating expenses	1,055		949		(106)		3,137		2,751		(386)

Operating income	154		95		59		654		517		137
Other income and (deductions)
Interest expense, net	(64)		(57)		(7)		(183)		(159)		(24)
Other, net	15		11		4		35		27		8
Total other income and (deductions)	(49)		(46)		(3)		(148)		(132)		(16)
Income before income taxes	105		49		56		506		385		121
Income taxes	23		4		(19)		108		32		(76)
Net income	$	82	$	45	$	37	$	398	$	353	$	45

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024 . Net income increased $37 million primarily due to electric distribution rates and decreases in storm costs, credit loss expense, and various operating expenses.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net Income increased $45 million primarily due to distribution and transmission rates and a decrease in storm costs, partially offset by an increase in interest expense and the derecognition of regulatory assets and liabilities for multi-year plan reconciliations that will no longer be filed as a result of the Next Generation Energy Act. See Note 2 — Regulatory Matters for additional information regarding the Next Generation Energy Act.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2025						Nine Months Ended September 30, 2025
	Increase (Decrease)						Increase
	Electric		Gas		Total		Electric		Gas		Total
Distribution	$	17	$	(9)	$	8	$	66	$	46	$	112
Transmission	(1)		—		(1)		10		—		10
Other	3		—		3		11		—		11
	19		(9)		10		87		46		133
Regulatory required programs	146		9		155		276		114		390
Total increase	$	165	$	—	$	165	$	363	$	160	$	523

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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	At September 30,
Number of Electric Customers	2025	2024
Residential	1,220,937	1,215,873
Small commercial & industrial	115,246	115,032
Large commercial & industrial	13,432	13,206
Public authorities & electric railroads	254	260
Total	1,349,869	1,344,371


	At September 30,
Number of Natural Gas Customers	2025	2024
Residential	660,241	658,485
Small commercial & industrial	37,731	37,752
Large commercial & industrial	6,404	6,353

Total	704,376	702,590

Distribution Revenue increased for the three and nine months ended September 30, 2025, compared to the same period in 2024, 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 remained relatively consistent for the three months ended September 30, 2025 and increased for the nine months ended September 30, 2025, compared to the same period in 2024, 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 increased for the three and nine months ended September 30, 2025 as compared to the same period in 2024, primarily driven by increases in service application fees.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, 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 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

The increase of $148 million and $356 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	(Decrease) Increase		Increase (Decrease)
Labor, other benefits, contracting, and materials	(8)		8
Credit loss expense	(7)		(2)
BSC costs	—		4
Pension and non-pension postretirement benefits expense	—		1
Storm-related costs	(9)		(16)
Other (a)	(19)		(6)
	(43)		(11)
Regulatory required programs (b)	1		23

Total (decrease) increase	$	(42)	$	12

__________

(a) For the three and nine months ended, reflects the absence of capital write-offs included in 2024. For the nine months ended, reflects the derecognition of regulatory assets for multi-year plan reconciliations that will no longer be filed as a result of the Next Generation Energy Act. See Note 2 — Regulatory Matters for additional information regarding the Next Generation Energy Act.

(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information.

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


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization	$	4	$	7
Regulatory required programs (a)	5		16
Regulatory asset amortization	(16)		(24)

Total decrease	$	(7)	$	(1)

__________

(a) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information.

Interest expense, net increased $7 million and $24 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, primarily due to the issuance of debt in the second quarter of 2025.

Taxes other than income taxes increased $7 million and $19 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, primarily due to increased property taxes.

Effective income tax rates were 21.9% and 8.2% for the three months ended September 30, 2025 and 2024, respectively, and 21.3% and 8.3% for the nine months ended September 30, 2025 and 2024. See Note 6 — 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 nine months ended September 30, 2025 compared to the same periods in 2024. See the Results of Operations for Pepco, DPL, and ACE for additional information.


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2025		2024				2025		2024
PHI	$	291	$	278	$	13	$	628	$	603	$	25
Pepco	156		140		16		337		323		14
DPL	55		55		—		163		156		7
ACE	82		83		(1)		138		133		5
Other (a)	(2)		—		(2)		(10)		(9)		(1)

__________

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

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net Income increased by $13 million primarily due to distribution rates and transmission rates at Pepco, partially offset by increases in interest and depreciation expense at Pepco.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net Income increased by $25 million primarily due to distribution rates at Pepco, DPL Delaware electric DSIC rates and natural gas rates, transmission rates at Pepco and DPL, and favorable weather conditions at DPL, partially offset by an increase in interest and depreciation expense and the lower impacts of the Maryland multi-year plans reconciliations at Pepco.

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Pepco

Results of Operations — Pepco


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2025		2024				2025		2024
Operating revenues	$	992	$	861	$	131	$	2,626	$	2,320	$	306


Operating expenses
Purchased power	367		294		(73)		942		808		(134)
Operating and maintenance	154		140		(14)		466		392		(74)
Depreciation and amortization	110		102		(8)		321		307		(14)
Taxes other than income taxes	122		114		(8)		344		317		(27)
Total operating expenses	753		650		(103)		2,073		1,824		(249)
Loss on sale of assets	—		—		—		1		—		1
Operating income	239		211		28		554		496		58
Other income and (deductions)
Interest expense, net	(53)		(50)		(3)		(159)		(142)		(17)
Other, net	11		11		—		31		43		(12)
Total other income and (deductions)	(42)		(39)		(3)		(128)		(99)		(29)
Income before income taxes	197		172		25		426		397		29
Income taxes	41		32		(9)		89		74		(15)
Net income	$	156	$	140	$	16	$	337	$	323	$	14

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net Income increased by $16 million primarily due to distribution and transmission rates, partially offset by increases in depreciation and interest expense.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net Income increased by $14 million primarily due to distribution and transmission rates, partially offset by lower impacts of the Maryland multi-year plans reconciliations and increases in depreciation and interest expense.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		Increase (Decrease)
Distribution	$	42	$	124
Transmission	1		12
Other	(2)		(7)
	41		129
Regulatory required programs	90		177
Total increase	$	131	$	306

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 intended to be impacted by abnormal weather or usage per customer as a result of a BSA that provides for a fixed distribution charge per customer class in the District of Columbia and per customer by customer class in Maryland. Therefore, changes in the number of customers only impacts Operating revenues in Maryland.

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Pepco


	At September 30,
Number of Electric Customers in Maryland	2025	2024
Residential	559,986	555,029
Small commercial & industrial	30,485	30,606
Large commercial & industrial	19,086	18,987
Public authorities & electric railroads	177	179
Total	609,734	604,801

Distribution Revenue increased for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans and customer growth in 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 the three and nine months ended September 30, 2025, compared to the same periods in 2024, primarily due to increases in underlying costs and capital investments.

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.

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

The increase of $73 million and $134 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, 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 September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		Increase (Decrease)
Maryland multi-year plan reconciliations (a)	$	3	$	27
Labor, other benefits, contracting, and materials	7		3
Storm-related costs	(1)		2
Pension and non-pension postretirement benefits expense	—		1
Credit loss expense	(2)		1
BSC and PHISCO costs	1		(2)


Other (b)	(4)		12
	4		44

Regulatory required programs (c)	10		30
Total increase	$	14	$	74

________ _

(a) See Note 2 - Regulatory Matters for additional information on multi-year plan reconciliations.

(b) Primarily relates to a revenue deferral mechanism approved by the MDPSC in 2024.

(c) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information.

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


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	Increase		Increase (Decrease)
Depreciation and amortization (a)	$	6	$	18
Regulatory asset amortization	2		4
Regulatory required programs (b)	—		(8)
Total increase	$	8	$	14

__________

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

(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters additional information.

Taxes other than income taxes increased $8 million and $27 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to increases in utility taxes, which are offset in revenues, and property taxes.

Interest expense, net increased $3 million and $17 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to an increase in interest rates and the issuance of debt in 2024 and 2025.

Other , net decreased $12 million for the nine months ended September 30, 2025, respectively, and stayed relatively consistent for the three months ended September 30, 2025, respectively, compared to the same periods in 2024, primarily due to lower AFUDC equity.

Effective income tax rates were 20.8% and 18.6% for the three months ended September 30, 2025 and 2024, respectively, and 20.9% and 18.6% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — 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 — DPL


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2025		2024				2025		2024
Operating revenues	$	491	$	462	$	29	$	1,460	$	1,343	$	117
Operating expenses
Purchased power and fuel	219		203		(16)		637		573		(64)
Operating and maintenance	94		92		(2)		296		284		(12)
Depreciation and amortization	63		62		(1)		189		183		(6)
Taxes other than income taxes	21		20		(1)		63		59		(4)
Total operating expenses	397		377		(20)		1,185		1,099		(86)

Operating income	94		85		9		275		244		31
Other income and (deductions)
Interest expense, net	(26)		(22)		(4)		(75)		(69)		(6)
Other, net	4		6		(2)		12		20		(8)
Total other income and (deductions)	(22)		(16)		(6)		(63)		(49)		(14)
Income before income taxes	72		69		3		212		195		17
Income taxes	17		14		(3)		49		39		(10)
Net income	$	55	$	55	$	—	$	163	$	156	$	7

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. Net income remained relatively consistent.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net income increased $7 million primarily due to Delaware electric DSIC rates and natural gas rates, favorable weather conditions at Delaware electric and natural gas service territories, and transmission rates, partially offset by increases in interest and depreciation expense.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2025						Nine Months Ended September 30, 2025
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	1	$	—	$	1	$	4	$	2	$	6
Volume	(5)		1		(4)		(3)		3		—
Distribution	6		3		9		14		7		21
Transmission	2		—		2		10		—		10
Other	1		—		1		2		—		2
	5		4		9		27		12		39
Regulatory required programs	19		1		20		65		13		78
Total increase	$	24	$	5	$	29	$	92	$	25	$	117

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 intended to be impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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

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demand. During the three months ended September 30, 2025 compared to the same period in 2024, Operating revenues related to weather remained relatively consistent. During the nine months ended September 30, 2025 compared to the same period in 2024, Operating revenues related to weather increased due to favorable weather conditions in DPL's Delaware electric and natural gas service territories.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL's Delaware service territory for the three and nine months ended September 30, 2025, compared to same periods in 2024 and normal weather consisted of the following:


	Three Months Ended September 30,			% Change
Delaware Electric Service Territory	2025	2024	Normal	2025 vs. 2024		2025 vs. Normal
Heating Degree-Days	3	13	28	(76.9)	%	(89.3)	%
Cooling Degree-Days	897	856	928	4.8	%	(3.3)	%

	Nine Months Ended September 30,			% Change
Delaware Electric Service Territory	2025	2024	Normal	2025 vs. 2024		2025 vs. Normal
Heating Degree-Days	2,774	2,620	2,896	5.9	%	(4.2)	%
Cooling Degree-Days	1,296	1,256	1,272	3.2	%	1.9	%


	Three Months Ended September 30,			% Change
Delaware Natural Gas Service Territory	2025	2024	Normal	2025 vs. 2024		2025 vs. Normal
Heating Degree-Days	3	13	34	(76.9)	%	(91.2)	%

	Nine Months Ended September 30,			% Change
Delaware Natural Gas Service Territory	2025	2024	Normal	2025 vs. 2024		2025 vs. Normal
Heating Degree-Days	2,774	2,620	2,970	5.9	%	(6.6)	%

Volume, exclusive of the effects of weather, decreased for the three months ended September 30, 2025 compared to the same period in 2024, primarily due to a decrease in customer usage. During the nine months ended September 30, 2025, Volume remained relatively consistent compared to the same period in 2024.


Electric Retail Deliveries to Delaware Customers (in GWhs)	Three Months Ended September 30,		% Change		Weather - Normal % Change (b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change (b)
	2025	2024					2025	2024
Residential	928	974	(4.7)	%	(6.1)	%	2,533	2,529	0.2	%	(2.1)	%
Small commercial & industrial	389	402	(3.2)	%	(3.5)	%	1,112	1,094	1.6	%	1.3	%
Large commercial & industrial	873	811	7.6	%	7.3	%	2,329	2,285	1.9	%	1.6	%
Public authorities & electric railroads	8	8	—	%	(0.1)	%	23	22	4.5	%	4.4	%
Total electric retail deliveries (a)	2,198	2,195	0.1	%	(0.7)	%	5,997	5,930	1.1	%	—	%

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	At September 30,
Number of Total Electric Customers (Maryland and Delaware)	2025	2024
Residential	494,232	489,634
Small commercial & industrial	65,322	64,626
Large commercial & industrial	1,257	1,267
Public authorities & electric railroads	632	598
Total	561,443	556,125

__________

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

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


Natural Gas Retail Deliveries to Delaware Customers (in mmcf)	Three Months Ended September 30,		% Change		Weather - Normal % Change (b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change (b)
	2025	2024					2025	2024
Residential	409	397	3.0	%	5.7	%	5,802	5,162	12.4	%	6.9	%
Small commercial & industrial	375	343	9.3	%	10.9	%	2,881	2,590	11.2	%	5.7	%
Large commercial & industrial	404	408	(1.0)	%	(1.1)	%	1,237	1,239	(0.2)	%	(0.1)	%
Transportation	1,239	1,190	4.1	%	4.3	%	4,626	4,491	3.0	%	1.4	%
Total natural gas deliveries (a)	2,427	2,338	3.8	%	4.7	%	14,546	13,482	7.9	%	4.3	%


	At September 30,
Number of Delaware Natural Gas Customers	2025	2024
Residential	131,494	130,885
Small commercial & industrial	10,134	10,110
Large commercial & industrial	14	14
Transportation	160	161
Total	141,802	141,170

__________

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

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

Distribution Revenue increased for the three and nine months ended September 30, 2025 compared to the same periods in 2024 primarily due to Delaware electric DSIC rates and natural gas rates that became effective in 2025.

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 nine months ended September 30, 2025 compared to the same periods in 2024, transmission revenue increased due to increases in underlying costs and capital investments.

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

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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.

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

The increase of $16 million and $64 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024 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 September 30, 2025		Nine Months Ended September 30, 2025
	(Decrease) Increase		Increase (Decrease)
Credit loss expense	$	(2)	$	3


Storm-related costs	(3)		(5)
Labor, other benefits, contracting, and materials	3		(4)
Other	1		2
	(1)		(4)
Regulatory required programs (a)	3		16
Total increase	$	2	$	12

__________

(a) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	Increase		Increase (Decrease)
Depreciation and amortization (a)	$	1	$	7
Regulatory asset amortization	—		—
Regulatory required programs (b)	—		(1)
Total increase	$	1	$	6

__________

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

(b) Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information

Taxes other than income taxes increased by $1 million and $4 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024 primarily due to an increase in property taxes.

Interest Expense, net increased by $4 million and $6 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024 primarily due to an increase in interest rates and the issuance of debt in 2024 and 2025 .

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Other, net decreased by $2 million and $8 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024 primarily due to a decrease in interest income and lower AFUDC equity.

Effective income tax rates were 23.6% and 20.3% for the three months ended September 30, 2025 and 2024, respectively, and 23.1% and 20.0% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — 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 September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2025		2024				2025		2024
Operating revenues	$	570	$	540	$	30	$	1,328	$	1,280	$	48


Operating expenses
Purchased power	286		245		(41)		616		557		(59)
Operating and maintenance	92		96		4		277		274		(3)
Depreciation and amortization	61		67		6		188		214		26
Taxes other than income taxes	2		2		—		7		7		—
Total operating expenses	441		410		(31)		1,088		1,052		(36)

Operating income	129		130		(1)		240		228		12
Other income and (deductions)
Interest expense, net	(20)		(21)		1		(62)		(59)		(3)
Other, net	2		4		(2)		8		12		(4)
Total other income and (deductions)	(18)		(17)		(1)		(54)		(47)		(7)
Income before income taxes	111		113		(2)		186		181		5
Income taxes	29		30		1		48		48		—
Net income	$	82	$	83	$	(1)	$	138	$	133	$	5

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024 . Net income remained relatively consistent.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. Net Income increased by $5 million primarily due to an increase in customer growth and a decrease in various operating expenses, offset by an increase in interest and depreciation expense.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	(Decrease) Increase		Increase (Decrease)
Distribution	$	—	$	4
Transmission	(2)		(2)
Other	—		2
	(2)		4

Regulatory required programs	32		44
Total increase	$	30	$	48

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not intended to be impacted by abnormal weather or usage per customer as a result of the CIP which 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 September 30,
Number of Electric Customers	2025	2024
Residential	509,739	507,060
Small commercial & industrial	62,923	62,761
Large commercial & industrial	2,730	2,848
Public authorities & electric railroads	745	707
Total	576,137	573,376

Distribution Revenue remained relatively consistent for the three months ended September 30, 2025 compared to the same period in 2024, and increased for the nine months ended September 30, 2025 compared to the same period in 2024, due to an increase in customer growth.

Transmission Revenues Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue remained relatively consistent for the three and nine months ended September 30, 2025 compared to the same periods in 2024.

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, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore, 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 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.

The increase of $41 million and $59 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024 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 September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting, and materials	$	6	$	3
Storm-related costs	(1)		—
Credit Loss Expense	(1)		—

BSC and PHISCO costs	(2)		(5)
Other	(2)		(4)
	—		(6)

Regulatory required programs	(4)		9
Total (decrease) increase	$	(4)	$	3

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


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization (a)	$	3	$	9
Regulatory asset amortization	(3)		(10)
Regulatory required programs	(6)		(25)
Total decrease	$	(6)	$	(26)

__________

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

Effective income tax rates were 26.1% and 26.5% for the three months ended September 30, 2025 and 2024, respectively and 25.8% and 26.5% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — 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 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

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 2024 Form 10-K and Notes 2 — Regulatory Matters and 11 — 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 nine months ended September 30, 2025 and 2024 by Registrant:


Increase in cash flows from operating activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income (loss)	$	361	$	80	$	296	$	45	$	25	$	14	$	7	$	5
Adjustments to reconcile net income to cash:
Non-cash operating activities	887		553		—		135		99		99		31		(34)

Collateral (paid) received, net	(46)		(52)		6		2		—		3		(2)		—
Income taxes	37		175		68		70		42		18		24		5
Pension and non-pension postretirement benefit contributions	(173)		(181)		(8)		(6)		32		—		—		4
Regulatory assets and liabilities, net	(584)		(550)		(43)		(45)		70		15		9		48
Changes in working capital and other assets and liabilities	385		(1)		39		41		113		(13)		27		122
Increase in cash flows from operating activities	$	867	$	24	$	358	$	242	$	381	$	136	$	96	$	150

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. Significant operating cash flow impacts for the Registrants for the nine months ended September 30, 2025 and 2024 were as follows:

• See Note 14 — 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 the Registrant 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 remained relatively consistent comparing the nine months ended September 30, 2025 to the nine months ended September 30, 2024. See Note 8 — Derivative Financial Instruments for additional information.

• See Note 6 — 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 relates to Exelon's increased contributions to the Qualified Plans during the nine months ended September 30, 2025. See Note 14 — Retirement Benefits of the 2024 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 differing from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $311 million and $266 million for the nine months ended September 30, 2025 and 2024, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $64 million, $27 million, $11 million, and $37 million for the nine months ended September 30, 2025 and $94 million, $34 million, $14 million, and $24 million for the nine months ended September 30, 2024, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the nine months ended September 30, 2025 and 2024. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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• Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $215 million and $385 million, respectively. 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 nine months ended September 30, 2025, the established pricing has resulted in both a receivable from, and payable to, nuclear-powered generating facilities. The change in receivable from nuclear-powered generating facilities, and the change in payable to nuclear-powered generating facilities, are reflected as a change in accounts receivable and a change in accounts payable and accrued expenses, respectively, within the cash flows from operations.

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the nine months ended September 30, 2025 and 2024 by Registrant:


(Decrease) increase in cash flows from investing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	(934)	$	(351)	$	(209)	$	(178)	$	(209)	$	(18)	$	2	$	(27)



Proceeds from sales of assets	(36)		—		—		—		2		2		—		—
Changes in intercompany money pool	—		—		(133)		—		—		—		—		—

Other investing activities	(16)		(3)		(4)		(3)		—		—		—		—
(Decrease) increase in cash flows from investing activities	$	(986)	$	(354)	$	(346)	$	(181)	$	(207)	$	(16)	$	2	$	(27)

Significant investing cash flow impacts for the Registrants for nine months ended September 30, 2025 and 2024 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.

• 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 nine months ended September 30, 2025 and 2024 by Registrant:


Increase (decrease) in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	713	$	493	$	(27)	$	161	$	(188)	$	(54)	$	(48)	$	(86)
Long-term debt, net	479		175		475		(150)		(17)		—		(17)		—
Changes in intercompany money pool	—		—		—		—		(9)		—		—		—
Issuance of common stock	25		—		—		—		—		—		—		—
Dividends paid on common stock	(70)		(28)		(110)		(18)		—		19		13		(32)

Distributions to member	—		—		—		—		1		—		—		—
Contributions from parent/member	—		(9)		(17)		294		64		(68)		(53)		13

Other financing activities	(1)		5		(3)		1		14		11		(2)		—
Increase (decrease) in cash flows from financing activities	$	1,146	$	636	$	318	$	288	$	(135)	$	(92)	$	(107)	$	(105)

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Significant financing cash flow impacts for the Registrants for the nine months ended September 30, 2025 and 2024 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 9 — 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 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the "Debt" section 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.

• Issuance of common stock relates to issuances of Exelon common stock during the first quarter of 2025. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

• 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 2024 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.

Debt

See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

During the nine months ended September 30, 2025, the following long-term debt was retired and/or redeemed.

Company (a)

Type

Interest Rate

Maturity

Amount

Exelon

Senior Notes

3.95

June 15, 2025

807

(a) On October 15, 2025, PECO redeemed $350 million of its 3.15% First Mortgage Bonds at maturity.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 2025 and for the fourth quarter of 2025 were as follows:

Period

Declaration Date

Shareholder of Record Date

Dividend Payable Date

Cash per Share (a)

First Quarter 2025

February 12, 2025

February 24, 2025

March 14, 2025

0.4000

Second Quarter 2025

April 29, 2025

May 12, 2025

June 13, 2025

0.4000

Third Quarter 2025

July 29, 2025

August 11, 2025

September 15, 2025

0.4000

Fourth Quarter 2025

October 29, 2025

November 10, 2025

December 15, 2025

0.4000

__________

(a) Exelon's Board of Directors approved an updated dividend policy for 2025. The 2025 quarterly dividend will be $0.40 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 $3.4 billion was available to support additional commercial paper as of September 30, 2025, and of which

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no financial institution has more than 6.2% 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 nine months ended September 30, 2025 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 9 — 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 2024 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.

At-the-Market Programs

On August 4, 2022, Exelon executed an equity distribution agreement (“2022 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 billion through August 3, 2025. On May 2, 2025, Exelon executed an additional equity distribution agreement ("2025 Equity Distribution Agreement" and, together with the August 4, 2022 Equity Distribution Agreement, "Equity Distribution Agreements"), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $2.5 billion through May 2, 2028. The 2025 Equity Distribution Agreement replaced the 2022 Equity Distribution Agreement. Exelon has no obligation to offer or sell any shares of Common stock under the 2025 Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the 2025 Equity Distribution Agreement.

During the first quarter of 2025, Exelon issued approximately 4.0 million shares of Common stock at an average net price of $42.98 per share. The net proceeds from the issuance were $173 million, which were used for general corporate purposes.

In addition, in the first quarter of 2025, Exelon entered into forward sale agreements for 5.7 million shares of Common stock, at a weighted-average net forward price of $43.24 per share. The forward sale agreements require Exelon to, at its election prior to December 15, 2025, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements.

In the second quarter of 2025, Exelon entered into forward sale agreements for 6.2 million shares, and 3.6 million shares of Common stock, at a weighted-average net forward price of $43.51, and $43.17 per share, respectively. The forward sale agreements require Exelon to, at its election prior to December 15, 2025 and November 16, 2026, respectively, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements.

In the third quarter of 2025, Exelon entered into forward sale agreements for 11.5 million shares at a weighted-average net forward price of $43.73 per share. The forward sale agreements require Exelon to, at its election prior to December 15, 2026 either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements.

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daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the nine months ended September 30, 2025, approximately 26.7 million shares under the forward sale agreements were not included in the calculation of diluted earnings per share because their effect would have been antidilutive.

Inclusive of the impact of the forward sale agreements, $1.6 billion of Common stock remained available for sale pursuant to the ATM program as of September 30, 2025.

Incremental Collateral Requirements

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at September 30, 2025 and available credit facility capacity prior to any incremental collateral at September 30, 2025:


	PJM Credit Policy Collateral		Other Incremental Collateral Required (a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	26	$	—	$	985
PECO	—		40		595
BGE	—		23		575

Pepco	1		—		235
DPL	—		13		267
ACE	—		—		230

__________

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

Capital Expenditure Spending

As of September 30, 2025, the most recent estimates of capital expenditures for plant additions and improvements for 2025 are as follows:


(In millions)	Transmission	Distribution	Gas	Total (a)
Exelon	N/A	N/A	N/A	$	8,975
ComEd	950	2,250	N/A	3,200
PECO	200	1,375	350	1,950
BGE	650	650	525	1,850
PHI	575	1,475	100	2,150
Pepco	250	750	N/A	1,000
DPL	150	325	75	525
ACE	150	275	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.

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Exelon’s estimated annual qualified pension contributions will be $275 million in 2025. 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, 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 2024 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 9 — 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 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for ComEd, BGE, PHI, Pepco, DPL, and ACE did not change for the nine months ended September 30, 2025. On January 17, 2025, Fitch Ratings affirmed and withdrew the long-term and short-term issuer default ratings along with individual securities ratings of the Registrants for commercial reasons. On February 7, 2025, S&P raised its long-term issuer credit rating for Exelon and PECO from 'BBB+' to 'A-', and raised its rating on Exelon’s senior unsecured debt from ‘BBB’ to 'BBB+'. S&P also affirmed its short-term issuer and commercial paper rating for Exelon and PECO of 'A-2'.

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Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of September 30, 2025, are presented in the following table:


	During the Nine Months Ended September 30, 2025				At September 30, 2025
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	578	$	—	$	64
PECO	336		(253)		222
BSC	—		(413)		(284)
PHI Corporate	—		(85)		(64)
PCI	62		—		62


	During the Nine Months Ended September 30, 2025				At September 30, 2025
PHI Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Pepco	$	20	$	(35)	$	—
DPL	48		(1)		—
ACE	—		(46)		—

Shelf Registration Statements

On February 21, 2024, PECO and BGE, as co-registrants, filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. On February 13, 2025, as most recently amended on March 27, 2025, Exelon Corporation and ComEd, as co-registrants filed a shelf registration statement with the SEC ("Exelon and ComEd Shelf Registration") for authorization of up to $12,575 million in additional security registration, to be used to issue Exelon Corporate debt securities and equity securities, as well as ComEd debt securities. The Exelon and ComEd Shelf Registration was declared effective by the SEC on April 8, 2025, and is effective through April 8, 2028. The ability of Exelon Corporation, ComEd, PECO and BGE to sell securities off their corresponding registration Statements, 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.

Pepco, DPL and ACE periodically issue securities through the private placement markets. Pepco, DPL and ACE's ability 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, current financial condition, securities ratings and market conditions.

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Regulatory Authorizations

The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

At September 30, 2025

Short-term Financing Authority

Remaining Long-term Financing Authority

Commission

Expiration Date

Amount

Commission

Expiration Date

Amount

ComEd (a)(b)

FERC

December 31, 2025

2,500

ICC

January 1, 2027 & May 1, 2027

1,593

PECO (c)

FERC

December 31, 2025

1,500

PAPUC

December 31, 2027

1,850

BGE (d)

FERC

December 31, 2025

700

MDPSC

N/A

1,850

Pepco (e)(f)(g)

FERC

December 31, 2025

500

MDPSC / DCPSC

December 31, 2025

100

DPL (e)(h)(i)

FERC

December 31, 2025

500

MDPSC / DEPSC

December 31, 2025

172

ACE (j)

NJBPU

December 31, 2025

350

NJBPU

December 31, 2026

775

__________

(a) On September 8, 2025, ComEd filed an application with the FERC to request a new short-term financing authority for $2.5 billion through December 31, 2027. ComEd expects approval of their application by December 31, 2025.

(b) On September 19, 2025, ComEd filed an application for $2.8 billion in new money long-term debt financing authority from the ICC and expects approval of their application by December 31, 2025.

(c) On September 8, 2025, PECO filed an application with the FERC to request a new short-term financing authority for $1.5 billion through December 31, 2027. PECO expects approval of their application by December 31, 2025.

(d) On September 8, 2025, BGE filed an application with the FERC to request a new short term financing authority for $900 million through December 31, 2027. BGE expects approval of their application by December 31, 2025.

(e) 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.

(f) On July 17, 2025, Pepco filed an application with the MDPSC and DCPSC to request a new long-term financing authority for $1.1 billion through December 31, 2028. On September 3, 2025, Pepco received approval of their application from the MDSPC. Pepco expects approval of their application from the DCPSC by December 31, 2025.

(g) On September 8, 2025, Pepco filed an application with the FERC to request a new short-term financing authority for $700 million through December 31, 2027. Pepco expects approval of their application by December 31, 2025.

(h) On September 3, 2025, DPL received approval from the MDSPC and DEPSC, respectively, for $700 million in new long-term financing authority, with an effective date of January 1, 2026.

(i) On September 8, 2025, DPL filed an application with the FERC to request a new short-term financing authority for $700 million through December 31, 2027. DPL expects approval of their application by December 31, 2025.

(j) On June 6, 2025, ACE filed an application with the NJBPU to extend their short-term financing authority through January 1, 2028. ACE expects approval of their application by December 31, 2025.

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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 8 — 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 7 — Retirement Benefits of the 2024 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 9 — 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. See Note 8 — 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.

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 8 — Derivative Financial Instruments and Note 10 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements.

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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 10 — 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) :	2025		2026		2027		2028		2029		2030 and Beyond		Total Fair Value
Prices based on model or other valuation methods (Level 3)	$	(10)	$	(20)	$	(20)	$	(20)	$	(19)	$	(39)	$	(128)

_________

(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 third quarter of 2025, 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 September 30, 2025, 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 third quarter of 2025 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 2024 Form 10-K, (b) Notes 3 — Regulatory Matters and 18 — Commitments and Contingencies of the 2024 Form 10-K, and (c) Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.

ITEM 1A. RISK FACTORS

Risks Related to All Registrants

At September 30, 2025, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2024 Form 10-K in ITEM 1A. RISK FACTORS.

ITEM 5. OTHER INFORMATION

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All Registrants

None of our officers or directors, as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934, adopted , modified, or terminated a “Rule 10b5-1 trading arrangement” or a “non-Rule 10b5-1 trading arrangement,” as defined in Item 408 of Regulation S-K, during the three months ended September 30, 2025.

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 applicable 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	One Hundred and Twenty-Fifth Supplemental Indenture dated as of August 15, 2025 from PECO to U.S. Bank National Association, as trustee	File No. 000-16844, Form 8-K dated September 10, 2025, Exhibit 4.1

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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2025 filed by the following officers for the following companies:


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 Joshua S. Levin for Commonwealth Edison Company

PECO Energy Company
Exhibit No.			Description
31-5			Filed by David M. Vahos for PECO Energy Company

31-6			Filed by Marissa E. Humphrey for PECO Energy Company

Baltimore Gas and Electric Company
Exhibit No.			Description
31-7			Filed by Tamla A. Olivier for Baltimore Gas and Electric Company

31-8			Filed by Michael J. Cloyd 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 Elizabeth Morgan Downs O'Donnell 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 Elizabeth Morgan Downs O'Donnell 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 Elizabeth Morgan Downs O'Donnell 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 Elizabeth Morgan Downs O'Donnell 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 September 30, 2025 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 Joshua S. Levin for Commonwealth Edison Company

PECO Energy Company
Exhibit No.			Description
32-5			Filed by David M. Vahos for PECO Energy Company

32-6			Filed by Marissa E. Humphrey for PECO Energy Company

Baltimore Gas and Electric Company
Exhibit No.			Description
32-7			Filed by Tamla A. Olivier for Baltimore Gas and Electric Company

32-8			Filed by Michael J. Cloyd 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 Elizabeth Morgan Downs O'Donnell 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 Elizabeth Morgan Downs O'Donnell 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 Elizabeth Morgan Downs O'Donnell 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 Elizabeth Morgan Downs O'Donnell 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)

151

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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)

November 4, 2025

152

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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/ JOSHUA S. LEVIN
Gil C. Quiniones						Joshua S. Levin
President, Chief Executive Officer (Principal Executive Officer), and Director						Senior Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

/s/ ERIN V. WHITE
Erin V. White
Director, Accounting (Principal Accounting Officer)

November 4, 2025

153

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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/ DAVID M. VAHOS						/s/ MARISSA E. HUMPHREY
David M. Vahos						Marissa E. Humphrey
President, Chief Executive Officer (Principal Executive Officer), and Director						Senior Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

/s/ MARIANA HUFFORD
Mariana Hufford
Director, Accounting (Principal Accounting Officer)

November 4, 2025

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.

BALTIMORE GAS AND ELECTRIC COMPANY


/s/ TAMLA A. OLIVIER						/s/ MICHAEL J. CLOYD
Tamla A. Olivier						Michael J. Cloyd
President, Chief Executive Officer (Principal Executive Officer), and Director						Senior Vice President, Chief Financial Officer, and Treasurer (Principal Financial Officer)

/s/ DAMON M. SCOLERI
Damon M. Scoleri
Director, Accounting (Principal Accounting Officer)

November 4, 2025

155

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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/ ELIZABETH MORGAN DOWNS O'DONNELL
J. Tyler Anthony						Elizabeth Morgan Downs O'Donnell
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)

November 4, 2025

156

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

POTOMAC ELECTRIC POWER COMPANY


/s/ J. TYLER ANTHONY						/s/ ELIZABETH MORGAN DOWNS O'DONNELL
J. Tyler Anthony						Elizabeth Morgan Downs O'Donnell
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)

November 4, 2025

157

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DELMARVA POWER & LIGHT COMPANY


/s/ J. TYLER ANTHONY						/s/ ELIZABETH MORGAN DOWNS O'DONNELL
J. Tyler Anthony						Elizabeth Morgan Downs O'Donnell
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)

November 4, 2025

158

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

ATLANTIC CITY ELECTRIC COMPANY


/s/ J. TYLER ANTHONY						/s/ ELIZABETH MORGAN DOWNS O'DONNELL
J. Tyler Anthony						Elizabeth Morgan Downs O'Donnell
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)

November 4, 2025

159

TABLE OF CONTENTS

Part I. Financial Information Item 1. Financial Statements Note 1 Significant Accounting Policies Note 2 Regulatory Matters Note 3 Revenue From Contracts with Customers Note 4 Segment Information Note 5 Accounts Receivable Note 6 Income Taxes Note 7 Retirement Benefits Note 8 Derivative Financial Instruments Note 9 Debt and Credit Agreements Note 10 Fair Value Of Financial Assets and Liabilities Note 11 Commitments and Contingencies Note 12 Shareholders' Equity Note 13 Changes in Accumulated Other Comprehensive Income Note 14 Supplemental Financial Information Note 15 Related Party Transactions Item 2. Management's Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosure About Market Risk Item 4. Controls and Procedures Part II Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 5. Other Information Item 6. Exhibits

Exhibits

Customer name	Ticker
The AES Corporation	AES
FirstEnergy Corp.	FE
Ford Motor Company	F
Pinnacle West Capital Corporation	PNW

Supplier name	Ticker
Eaton Corporation plc	ETN
General Electric Company	GE
Duke Energy Corporation	DUK
Honeywell International Inc.	HON
3M Company	MMM
The Southern Company	SO
Dominion Energy, Inc.	D
Parker-Hannifin Corporation	PH
Consolidated Edison, Inc.	ED
PG&E Corporation	PCG
Sempra Energy	SRE

EXC 10-Q Quarter ended Sept. 30, 2025

Exhibits