exc-20260930

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, 2026


☐ 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, 2026 was:


Exelon Corporation Common Stock, without par value			1,034,896,686
Commonwealth Edison Company Common Stock, $12.50 par value			127,021,427
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			61
			4. Segment Information			63
			5. Accounts Receivable			73
			6. Property, Plant, and Equipment			75
			7. Income Taxes			76
			8. Retirement Benefits			81
			9. Derivative Financial Instruments			82
			10. Debt and Credit Agreements			85
			11. Fair Value of Financial Assets and Liabilities			87
			12. Commitments and Contingencies			95
			13. Shareholders' Equity			102
			14. Changes in Accumulated Other Comprehensive Income			103

			15. Supplemental Financial Information			104
			16. Related Party Transactions			108


		Page No.


ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	111
	Exelon Corporation	111
	Executive Overview	111
	Financial Results of Operations	111
	Significant 2026 Transactions and Developments	114


	Other Key Business Drivers and Management Strategies	116
	Critical Accounting Policies and Estimates	117
	Results of Operations By Registrant	118
	Commonwealth Edison Company	118
	PECO Energy Company	121
	Baltimore Gas and Electric Company	125
	Pepco Holdings LLC	128
	Potomac Electric Power Company	129
	Delmarva Power & Light Company	132
	Atlantic City Electric Company	136
	Liquidity and Capital Resources	139

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	149
ITEM 4.	CONTROLS AND PROCEDURES	150
PART II.	OTHER INFORMATION	151
ITEM 1.	LEGAL PROCEEDINGS	151
ITEM 1A.	RISK FACTORS	151

ITEM 5.	OTHER INFORMATION	151
ITEM 6.	EXHIBITS	151
SIGNATURES		154
	Exelon Corporation	154
	Commonwealth Edison Company	155
	PECO Energy Company	156
	Baltimore Gas and Electric Company	157
	Pepco Holdings LLC	158
	Potomac Electric Power Company	159
	Delmarva Power & Light Company	160
	Atlantic City Electric Company	161

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
Pepco Energy Services or PES						Pepco Energy Services, Inc. and its subsidiaries
PHI Corporate						PHI in its corporate capacity as a holding company
PHISCO						PHI Service Company
Former Related Entities
Constellation						Constellation Energy Corporation and Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLC, a subsidiary of Exelon as of December 31, 2021 prior to separation on February 1, 2022)

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note - of the 2025 Form 10-K						Reference to specific Combined Note to Consolidated Financial Statements within Exelon's 2025 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
Convertible Senior Notes						Exelon's 3.25% Convertible Senior Notes due 2029
CMC						Carbon Mitigation Credit
CRGA						Clean and Reliable Grid Affordability Act
CODMs						Chief Operating Decision Makers
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
FERC						Federal Energy Regulatory Commission
GAAP						Generally Accepted Accounting Principles in the United States
GWhs						Gigawatt hours
ICC						Illinois Commerce Commission
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
NJBPU						New Jersey Board of Public Utilities
NOLC						Tax Net Operating Loss Carryforward
NPNS						Normal Purchase Normal Sale scope exception

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
NPS						National Park Service
NRD						Natural Resources Damages
OCI						Other Comprehensive Income
OPEB						Other Postretirement Employee Benefits
PAPUC						Pennsylvania Public Utility Commission
PJM						PJM Interconnection, LLC
PLR						Private Letter Ruling
PP&E						Property, Plant, and Equipment
PRPs						Potentially Responsible Parties
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
S&P						Standard & Poor’s Ratings Services
SEC						United States Securities and Exchange Commission
SOFR						Secured Overnight Financing Rate
SOS						Standard Offer Service
TCJA						Tax Cuts and Jobs Act
USAO						United States Attorney's Office for the Northern District of Illinois

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;

•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 power generation resources to meet actual or forecasted demand or disruptions at 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

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

Table of Contents

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 2025 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)	2026		2025		2026		2025
Operating revenues
Electric operating revenues	$	7,103	$	6,690	$	18,971	$	17,872
Natural gas operating revenues	251		235		1,695		1,595
Revenues from alternative revenue programs	(35)		(220)		(138)		(621)
Total operating revenues	7,319		6,705		20,528		18,846
Operating expenses
Purchased power	2,865		2,645		7,380		6,640
Purchased fuel	52		47		524		471

Operating and maintenance	1,564		1,172		4,416		3,840
Depreciation and amortization	991		912		2,910		2,717
Taxes other than income taxes	468		429		1,335		1,216
Total operating expenses	5,940		5,205		16,565		14,884

Gain on sale of assets	—		—		—		1


Operating income	1,379		1,500		3,963		3,963
Other income and (deductions)
Interest expense, net	(587)		(531)		(1,702)		(1,560)
Interest expense to affiliates	(6)		(7)		(19)		(18)
Other, net	97		68		256		185
Total other income and (deductions)	(496)		(470)		(1,465)		(1,393)
Income before income taxes	883		1,030		2,498		2,570
Income taxes	154		155		454		396





Net income attributable to common shareholders	$	729	$	875	$	2,044	$	2,174






Comprehensive income, net of income taxes
Net income	$	729	$	875	$	2,044	$	2,174
Other comprehensive income, net of income taxes
Pension and non-pension postretirement benefit plans:

Actuarial losses reclassified to periodic benefit cost	7		5		21		16
Pension and non-pension postretirement benefit plans valuation adjustments	—		—		3		5
Unrealized gain (loss) on cash flow hedges	10		(2)		5		(16)



Other comprehensive income	17		3		29		5


Comprehensive income attributable to common shareholders	$	746	$	878	$	2,073	$	2,179

Average shares of common stock outstanding:
Basic	1,035		1,011		1,028		1,010
Assumed exercise and/or distributions of stock-based awards(a)	2		2		2		1
Diluted	1,037		1,013		1,030		1,011

Earnings per average common share
Basic	$	0.70	$	0.87	$	1.99	$	2.15
Diluted	$	0.70	$	0.86	$	1.98	$	2.15

__________

(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)	2026		2025
Cash flows from operating activities
Net income	$	2,044	$	2,174
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion	2,912		2,719


Gain on sales of assets	—		(1)

Asset disallowances, impairments and write-offs	232		—
Deferred income taxes and amortization of investment tax credits	564		293
Net fair value changes related to derivatives	—		3


Other non-cash operating activities	594		1,088
Changes in assets and liabilities:
Accounts receivable	379		(422)
Inventories	(96)		(41)
Accounts payable and accrued expenses	(1)		165

Collateral received (paid), net	39		(25)
Income taxes	(136)		19
Regulatory assets and liabilities, net	(1,063)		(390)
Pension and non-pension postretirement benefit contributions	(370)		(313)
Other assets and liabilities	306		(259)
Net cash flows provided by operating activities	5,404		5,010
Cash flows from investing activities
Capital expenditures	(6,799)		(6,095)





Proceeds from sales of assets	—		2


Other investing activities	12		(7)
Net cash flows used in investing activities	(6,787)		(6,100)
Cash flows from financing activities
Changes in short-term borrowings	(178)		(779)
Proceeds from short-term borrowings with maturities greater than 90 days	500		—

Issuance of long-term debt	4,425		4,925
Retirement of long-term debt	(1,600)		(807)

Issuance of common stock	483		173



Dividends paid on common stock	(1,294)		(1,212)
Proceeds from employee stock plans	37		24

Other financing activities	(71)		(75)
Net cash flows provided by financing activities	2,302		2,249
Increase in cash, restricted cash, and cash equivalents	919		1,159
Cash, restricted cash, and cash equivalents at beginning of period	1,201		939
Cash, restricted cash, and cash equivalents at end of period	$	2,120	$	2,098

Supplemental cash flow information
Decrease in capital expenditures not paid	(4)		(12)

Decrease in PP&E related to ARO update	(4)		(5)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	September 30, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	1,469	$	626
Restricted cash and cash equivalents	602		525

Accounts receivable
Customer accounts receivable	3,669		3,732
Customer allowance for credit losses	(507)		(435)
Customer accounts receivable, net	3,162		3,297
Other accounts receivable	1,574		1,879
Other allowance for credit losses	(96)		(94)
Other accounts receivable, net	1,478		1,785
Inventories, net
Fossil fuel	99		88
Materials and supplies	863		780
Regulatory assets	1,278		1,359
Prepaid renewable energy credits	466		563
Other	523		523
Total current assets	9,940		9,546
Property, plant, and equipment (net of accumulated depreciation and amortization of $21,437 and $20,080 as of September 30, 2026 and December 31, 2025, respectively)	88,557		84,318
Deferred debits and other assets
Regulatory assets	9,560		9,214
Goodwill	6,630		6,630
Receivable related to Regulatory Agreement Units	5,196		4,755
Investments	336		312
Other	2,018		1,795
Total deferred debits and other assets	23,740		22,706
Total assets	$	122,237	$	116,570

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Exelon Corporation and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	September 30, 2026		December 31, 2025
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	934	$	612
Long-term debt due within one year	1,078		1,665
Accounts payable	3,711		3,721
Accrued expenses	1,692		1,582
Payables to affiliates	5		5
Customer deposits	609		533
Regulatory liabilities	551		1,128
Mark-to-market derivative liabilities	21		30
Unamortized energy contract liabilities	4		5
Renewable energy credit obligations	364		473
Other	675		577
Total current liabilities	9,644		10,331
Long-term debt	50,791		47,413
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	14,596		13,715
Regulatory liabilities	11,684		11,016
Pension obligations	1,428		1,749
Non-pension postretirement benefit obligations	572		546
Asset retirement obligations	318		321
Mark-to-market derivative liabilities	96		106
Unamortized energy contract liabilities	13		16
Other	2,573		2,169
Total deferred credits and other liabilities	31,280		29,638
Total liabilities	92,105		87,772
Commitments and contingencies

Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 1,035 shares and 1,023 shares outstanding as of September 30, 2026 and December 31, 2025, respectively)	22,663		22,106
Treasury stock, at cost (2 shares as of September 30, 2026 and December 31, 2025)	(123)		(123)
Retained earnings	8,325		7,577
Accumulated other comprehensive loss, net	(733)		(762)
Total shareholders’ equity	30,132		28,798


Total liabilities and shareholders’ equity	$	122,237	$	116,570

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, 2026
(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, 2025	1,024,401	$	22,106	$	(123)	$	7,577	$	(762)	$	28,798
Net income	—	—		—		919		—		919
Long-term incentive plan activity	338	10		—		—		—		10
Employee stock purchase plan activity	302	13		—		—		—		13




Common stock dividends ($0.42/common share)	—	—		—		(431)		—		(431)
Other comprehensive income, net of income taxes	—	—		—		—		6		6

Balance at March 31, 2026	1,025,041	$	22,129	$	(123)	$	8,065	$	(756)	$	29,315
Net income	—	—		—		396		—		396
Long-term incentive plan activity	51	14		—		—		—		14
Employee stock purchase plan activity	317	15		—		—		—		15
Issuance of common stock	8,682	382		—		—		—		382



Common stock dividends ($0.42/common share)	—	—		—		(430)		—		(430)
Other comprehensive income, net of income taxes	—	—		—		—		6		6

Balance at June 30, 2026	1,034,091	$	22,540	$	(123)	$	8,031	$	(750)	$	29,698
Net income	—	—		—		729		—		729
Long-term incentive plan activity	13	7		—		—		—		7
Employee stock purchase plan activity	302	15		—		—		—		15
Issuance of common stock	2,327	101		—		—		—		101


Common stock dividends ($0.42/common share)	—	—		—		(435)		—		(435)
Other comprehensive income, net of income taxes	—	—		—		—		17		17
Balance at September 30, 2026	1,036,733	$	22,663	$	(123)	$	8,325	$	(733)	$	30,132

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

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)	2026		2025		2026		2025
Operating revenues
Electric operating revenues	$	2,483	$	2,479	$	6,415	$	6,682
Revenues from alternative revenue programs	(15)		(206)		(62)		(525)
Operating revenues from affiliates	2		2		15		19
Total operating revenues	2,470		2,275		6,368		6,176
Operating expenses
Purchased power	783		806		1,814		2,044

Operating and maintenance	359		313		1,033		958
Operating and maintenance from affiliates	105		96		317		296
Depreciation and amortization	438		395		1,258		1,162
Taxes other than income taxes	133		107		345		303
Total operating expenses	1,818		1,717		4,767		4,763

Operating income	652		558		1,601		1,413
Other income and (deductions)
Interest expense, net	(146)		(132)		(418)		(385)
Interest expense to affiliates, net	(3)		(3)		(10)		(10)
Other, net	43		33		116		86
Total other income and (deductions)	(106)		(102)		(312)		(309)
Income before income taxes	546		456		1,289		1,104
Income taxes	140		83		324		201
Net income	$	406	$	373	$	965	$	903
Comprehensive income	$	406	$	373	$	965	$	903

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)	2026		2025
Cash flows from operating activities
Net income	$	965	$	903
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	1,258		1,162

Deferred income taxes and amortization of investment tax credits	220		21

Other non-cash operating activities	159		634
Changes in assets and liabilities:
Accounts receivable	595		(347)
Receivables from and payables to affiliates, net	(13)		(16)
Inventories	(39)		12
Accounts payable and accrued expenses	138		112
Collateral paid, net	(9)		(31)
Income taxes	6		66
Regulatory assets and liabilities, net	(1,026)		(128)
Pension and non-pension postretirement benefit contributions	(223)		(192)
Other assets and liabilities	63		(136)
Net cash flows provided by operating activities	2,094		2,060
Cash flows from investing activities
Capital expenditures	(2,522)		(1,970)




Other investing activities	8		5
Net cash flows used in investing activities	(2,514)		(1,965)
Cash flows from financing activities
Changes in short-term borrowings	—		(36)


Issuance of long-term debt	1,425		725
Retirement of long-term debt	(500)		—
Dividends paid on common stock	(654)		(610)
Contributions from parent	380		108
Other financing activities	(15)		(7)
Net cash flows provided by financing activities	636		180
Increase in cash, restricted cash, and cash equivalents	216		275
Cash, restricted cash, and cash equivalents at beginning of period	663		632
Cash, restricted cash, and cash equivalents at end of period	$	879	$	907

Supplemental cash flow information
Increase in capital expenditures not paid	$	46	$	74

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, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	300	$	159
Restricted cash and cash equivalents	530		454
Accounts receivable
Customer accounts receivable	1,093		1,058
Customer allowance for credit losses	(105)		(115)
Customer accounts receivable, net	988		943
Other accounts receivable	475		1,155
Other allowance for credit losses	(26)		(23)
Other accounts receivable, net	449		1,132

Receivables from affiliates	5		5

Inventories, net	305		268

Regulatory assets	602		595

Other	296		217
Total current assets	3,475		3,773
Property, plant, and equipment (net of accumulated depreciation and amortization of $8,825 and $8,291 as of September 30, 2026 and December 31, 2025, respectively)	33,977		32,255
Deferred debits and other assets
Regulatory assets	2,970		2,687

Goodwill	2,625		2,625

Receivable related to Regulatory Agreement Units	4,598		4,313
Investments	7		6
Prepaid pension asset	1,436		1,284

Other	1,450		1,342
Total deferred debits and other assets	13,086		12,257
Total assets	$	50,538	$	48,285

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, 2026		December 31, 2025
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities

Long-term debt due within one year	$	350	$	500
Accounts payable	1,255		1,033
Accrued expenses	451		474
Payables to affiliates	68		81
Customer deposits	246		192
Regulatory liabilities	197		846
Mark-to-market derivative liabilities	21		25

Other	344		288
Total current liabilities	2,932		3,439
Long-term debt	13,317		12,253
Long-term debt to financing trust	206		206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	6,107		5,828
Regulatory liabilities	9,726		9,163
Asset retirement obligations	199		193

Non-pension postretirement benefit obligations	160		151

Mark-to-market derivative liabilities	96		106

Other	1,499		1,341
Total deferred credits and other liabilities	17,787		16,782
Total liabilities	34,242		32,680
Commitments and contingencies
Shareholders’ equity
Common stock	1,588		1,588


Other paid-in capital	11,399		11,019
Retained earnings	3,309		2,998

Total shareholders’ equity	16,296		15,605
Total liabilities and shareholders’ equity	$	50,538	$	48,285

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, 2026
(In millions)	Common Stock		Other Paid-In Capital		Retained Earnings		Total Shareholders’ Equity
Balance at December 31, 2025	$	1,588	$	11,019	$	2,998	$	15,605
Net income	—		—		310		310
Common stock dividends	—		—		(218)		(218)
Contributions from parent	—		256		—		256
Balance at March 31, 2026	$	1,588	$	11,275	$	3,090	$	15,953
Net income	—		—		249		249
Common stock dividends	—		—		(219)		(219)
Contributions from parent	—		—		—		—
Balance at June 30, 2026	$	1,588	$	11,275	$	3,120	$	15,983
Net income	—		—		406		406
Common stock dividends	—		—		(217)		(217)
Contributions from parent	—		124		—		124
Balance at September 30, 2026	$	1,588	$	11,399	$	3,309	$	16,296

	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

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)	2026		2025		2026		2025
Operating revenues
Electric operating revenues	$	1,150	$	1,093	$	3,157	$	2,932
Natural gas operating revenues	84		82		614		578
Revenues from alternative revenue programs	1		2		10		(6)
Operating revenues from affiliates	5		3		13		9
Total operating revenues	1,240		1,180		3,794		3,513
Operating expenses
Purchased power	475		428		1,278		1,093
Purchased fuel	19		18		217		195

Operating and maintenance	258		183		760		690
Operating and maintenance from affiliates	55		58		189		182
Depreciation and amortization	126		115		373		336
Taxes other than income taxes	73		69		204		183
Total operating expenses	1,006		871		3,021		2,679

Operating income	234		309		773		834
Other income and (deductions)
Interest expense, net	(74)		(63)		(213)		(179)
Interest expense to affiliates, net	(2)		(2)		(6)		(9)
Other, net	15		11		39		29
Total other income and (deductions)	(61)		(54)		(180)		(159)
Income before income taxes	173		255		593		675
Income taxes	8		5		31		23

Net income	$	165	$	250	$	562	$	652
Comprehensive income	$	165	$	250	$	562	$	652

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)	2026		2025
Cash flows from operating activities
Net income	$	562	$	652
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	373		336


Deferred income taxes and amortization of investment tax credits	280		(60)
Other non-cash operating activities	49		69
Changes in assets and liabilities:
Accounts receivable	(179)		(94)
Receivables from and payables to affiliates, net	(1)		(8)
Inventories	(15)		(8)
Accounts payable and accrued expenses	100		(4)
Collateral (paid) received, net	—		6
Income taxes	(269)		13
Regulatory assets and liabilities, net	(48)		(26)
Pension and non-pension postretirement benefit contributions	(13)		(11)
Other assets and liabilities	3		(10)
Net cash flows provided by operating activities	842		855
Cash flows from investing activities
Capital expenditures	(1,469)		(1,334)
Changes in Exelon intercompany money pool	(301)		(222)

Other investing activities	(10)		1
Net cash flows used in investing activities	(1,780)		(1,555)
Cash flows from financing activities

Changes in short-term borrowings	—		(192)
Issuance of long-term debt	750		1,050



Dividends paid on common stock	(410)		(410)
Contributions from parent	594		578


Other financing activities	(5)		(10)
Net cash flows provided by financing activities	929		1,016
(Decrease) increase in cash, restricted cash, and cash equivalents	(9)		316
Cash, restricted cash, and cash equivalents at beginning of period	116		48
Cash, restricted cash, and cash equivalents at end of period	$	107	$	364

Supplemental cash flow information
Increase in capital expenditures not paid	$	30	$	81

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, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	107	$	116

Accounts receivable
Customer accounts receivable	709		811
Customer allowance for credit losses	(135)		(137)
Customer accounts receivable, net	574		674
Other accounts receivable	364		144
Other allowance for credit losses	(16)		(18)
Other accounts receivable, net	348		126

Receivables from affiliates	1		—


Inventories, net
Fossil fuel	45		43
Materials and supplies	96		83
Prepaid utility taxes	16		—
Prepaid renewable energy credits	29		55
Regulatory assets	111		72

Other	328		34
Total current assets	1,655		1,203
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,228 and $4,131 as of September 30, 2026 and December 31, 2025, respectively)	17,076		15,922
Deferred debits and other assets
Regulatory assets	1,430		1,275




Receivable related to Regulatory Agreement Units	598		442
Investments	49		45
Prepaid pension asset	445		441

Other	61		34
Total deferred debits and other assets	2,583		2,237
Total assets	$	21,314	$	19,362

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, 2026		December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities


Accounts payable	799		811
Accrued expenses	371		483
Payables to affiliates	35		35

Customer deposits	107		93
Renewable energy credit obligations	30		56
Regulatory liabilities	129		140


Other	60		40
Total current liabilities	1,531		1,658
Long-term debt	7,143		6,396
Long-term debt to financing trusts	184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	3,021		2,594
Regulatory liabilities	604		449
Asset retirement obligations	25		26
Non-pension postretirement benefit obligations	291		286





Other	109		109
Total deferred credits and other liabilities	4,050		3,464
Total liabilities	12,908		11,702
Commitments and contingencies
Shareholder’s equity
Common stock	5,816		5,222


Retained earnings	2,590		2,438


Total shareholder’s equity	8,406		7,660
Total liabilities and shareholder's equity	$	21,314	$	19,362

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, 2026
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2025	$	5,222	$	2,438	$	7,660
Net income	—		278		278
Common stock dividends	—		(137)		(137)
Contributions from parent	567		—		567
Balance at March 31, 2026	$	5,789	$	2,579	$	8,368
Net income	—		119		119
Common stock dividends	—		(136)		(136)
Contributions from parent	—		—		—
Balance at June 30, 2026	$	5,789	$	2,562	$	8,351
Net income	—		165		165
Common stock dividends	—		(137)		(137)
Contributions from parent	27		—		27
Balance at September 30, 2026	$	5,816	$	2,590	$	8,406

	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

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)		2026		2025		2026		2025
Operating revenues
Electric operating revenues		$	1,252	$	1,102	$	3,554	$	2,978
Natural gas operating revenues		127		125		883		870
Revenues from alternative revenue programs		(18)		(20)		(35)		(63)
Operating revenues from affiliates		2		2		7		6
Total operating revenues		1,363		1,209		4,409		3,791
Operating expenses
Purchased power		636		547		1,787		1,365
Purchased fuel		14		21		215		219

Operating and maintenance		236		179		716		621
Operating and maintenance from affiliates		56		60		194		186
Depreciation and amortization		161		155		496		473
Taxes other than income taxes		100		93		301		273
Total operating expenses		1,203		1,055		3,709		3,137

Operating income		160		154		700		654
Other income and (deductions)
Interest expense, net		(73)		(64)		(202)		(183)
Other, net		26		15		64		35
Total other income and (deductions)		(47)		(49)		(138)		(148)
Income before income taxes		113		105		562		506
Income taxes		23		23		119		108
Net income		$	90	$	82	$	443	$	398
Comprehensive income		$	90	$	82	$	443	$	398

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)	2026		2025
Cash flows from operating activities
Net income	$	443	$	398
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	496		473
Asset disallowances, impairments and write-offs	37		—
Deferred income taxes and amortization of investment tax credits	220		53

Other non-cash operating activities	95		127
Changes in assets and liabilities:
Accounts receivable	5		34
Receivables from and payables to affiliates, net	(6)		(15)
Inventories	(23)		(10)
Accounts payable and accrued expenses	(14)		88
Collateral received, net	—		2
Income taxes	(176)		19
Regulatory assets and liabilities, net	42		(114)
Pension and non-pension postretirement benefit contributions	(47)		(40)
Other assets and liabilities	74		116
Net cash flows provided by operating activities	1,146		1,131
Cash flows from investing activities
Capital expenditures	(1,224)		(1,211)

Other investing activities	7		7
Net cash flows used in investing activities	(1,217)		(1,204)
Cash flows from financing activities
Changes in short-term borrowings	—		(175)
Issuance of long-term debt	925		650
Retirement of long-term debt	(350)		—


Dividends paid on common stock	(341)		(294)
Contributions from parent	472		531
Other financing activities	(10)		(8)
Net cash flows provided by financing activities	696		704
Increase in cash, restricted cash, and cash equivalents	625		631
Cash, restricted cash, and cash equivalents at beginning of period	220		34
Cash, restricted cash, and cash equivalents at end of period	$	845	$	665

Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	67	$	(46)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Baltimore Gas and Electric Company

Balance Sheets

(Unaudited)


(In millions)	September 30, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	842	$	217
Restricted cash and cash equivalents	3		3
Accounts receivable
Customer accounts receivable	889		887
Customer allowance for credit losses	(131)		(68)
Customer accounts receivable, net	758		819
Other accounts receivable	147		100
Other allowance for credit losses	(3)		(4)
Other accounts receivable, net	144		96

Receivables from affiliates	—		1


Inventories, net
Fossil fuel	44		36
Materials and supplies	88		74
Prepaid utility taxes	76		126
Regulatory assets	90		175
Prepaid renewable energy credits	135		189
Other	18		14
Total current assets	2,198		1,750
Property, plant, and equipment (net of accumulated depreciation and amortization of $5,452 and $5,234 as of September 30, 2026 and December 31, 2025, respectively)	15,172		14,385
Deferred debits and other assets
Regulatory assets	790		804
Investments	15		10


Prepaid pension asset	213		194

Other	53		41
Total deferred debits and other assets	1,071		1,049
Total assets	$	18,441	$	17,184

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Baltimore Gas and Electric Company

Balance Sheets

(Unaudited)


(In millions)	September 30, 2026		December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities

Long-term debt due within one year	$	—	$	350
Accounts payable	670		640
Accrued expenses	231		352
Payables to affiliates	35		39
Customer deposits	121		125
Regulatory liabilities	48		31

Renewable energy credit obligations	143		194
Other	62		39
Total current liabilities	1,310		1,770
Long-term debt	6,610		5,691
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,509		2,242
Regulatory liabilities	553		595
Asset retirement obligations	33		36
Non-pension postretirement benefit obligations	137		144



Other	113		104
Total deferred credits and other liabilities	3,345		3,121
Total liabilities	11,265		10,582
Commitments and contingencies
Shareholder's equity
Common stock	4,486		4,014

Retained earnings	2,690		2,588


Total shareholder's equity	7,176		6,602


Total liabilities and shareholder's equity	$	18,441	$	17,184

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, 2026
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2025	$	4,014	$	2,588	$	6,602
Net income	—		298		298
Common stock dividends	—		(114)		(114)
Contributions from parent	—		—		—
Balance at March 31, 2026	$	4,014	$	2,772	$	6,786
Net income	—		55		55
Common stock dividends	—		(113)		(113)
Contributions from parent	474		—		474
Balance at June 30, 2026	$	4,488	$	2,714	$	7,202
Net income	—		90		90
Common stock dividends	—		(114)		(114)
Distributions to parent	(2)		—		(2)
Balance at September 30, 2026	$	4,486	$	2,690	$	7,176

	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

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)	2026		2025		2026		2025
Operating revenues
Electric operating revenues	$	2,218	$	2,016	$	5,846	$	5,280
Natural gas operating revenues	40		27		197		148
Revenues from alternative revenue programs	(3)		6		(51)		(27)
Operating revenues from affiliates	5		2		10		7
Total operating revenues	2,260		2,051		6,002		5,408
Operating expenses
Purchased power	971		864		2,501		2,138
Purchased fuel	19		8		92		57

Operating and maintenance	510		290		1,212		876
Operating and maintenance from affiliates	39		45		157		148
Depreciation and amortization	250		234		741		701
Taxes other than income taxes	150		150		445		426
Total operating expenses	1,939		1,591		5,148		4,346

Gain on sale of assets	—		—		—		1
Operating income	321		460		854		1,063
Other income and (deductions)
Interest expense, net	(110)		(102)		(323)		(303)
Interest expense to affiliates, net	(1)		—		(3)		(2)
Other, net	23		18		62		54
Total other income and (deductions)	(88)		(84)		(264)		(251)
Income before income taxes	233		376		590		812
Income taxes	46		85		125		184

Net income	$	187	$	291	$	465	$	628








Comprehensive income	$	187	$	291	$	465	$	628

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)	2026		2025
Cash flows from operating activities
Net income	$	465	$	628
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion	741		703

Gain on sales of assets	—		(1)
Asset disallowances, impairments and write-offs	195		—
Deferred income taxes and amortization of investment tax credits	78		93

Other non-cash operating activities	188		172
Changes in assets and liabilities:
Accounts receivable	(52)		(28)
Receivables from and payables to affiliates, net	(8)		(17)
Inventories	(20)		(36)
Accounts payable and accrued expenses	28		21

Collateral received, net	38		1
Income taxes	(2)		(13)
Regulatory assets and liabilities, net	(16)		(88)
Pension and non-pension postretirement benefit contributions	(59)		(47)
Other assets and liabilities	43		(20)
Net cash flows provided by operating activities	1,619		1,368
Cash flows from investing activities
Capital expenditures	(1,521)		(1,552)
Proceeds from sales of long-lived assets	—		2



Other investing activities	5		—
Net cash flows used in investing activities	(1,516)		(1,550)
Cash flows from financing activities
Changes in short-term borrowings	(612)		(364)


Issuance of long-term debt	550		500

Changes in Exelon intercompany money pool	16		1



Distributions to member	(410)		(548)
Contributions from member	486		569


Other financing activities	(21)		(19)
Net cash flows provided by financing activities	9		139
Increase (decrease) in cash, restricted cash, and cash equivalents	112		(43)
Cash, restricted cash, and cash equivalents at beginning of period	141		163
Cash, restricted cash, and cash equivalents at end of period	$	253	$	120

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(132)	$	(92)

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, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	207	$	103
Restricted cash and cash equivalents	46		38
Accounts receivable
Customer accounts receivable	976		975
Customer allowance for credit losses	(136)		(115)
Customer accounts receivable, net	840		860
Other accounts receivable	317		292
Other allowance for credit losses	(51)		(49)
Other accounts receivable, net	266		243

Receivables from affiliates	7		14


Inventories, net
Fossil fuel	10		9
Materials and supplies	375		357

Prepaid utility taxes	31		77
Regulatory assets	310		352

Prepaid renewable energy credits	166		201
Other	39		34
Total current assets	2,297		2,288
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,846 and $4,350 as of September 30, 2026 and December 31, 2025, respectively)	21,946		21,377
Deferred debits and other assets
Regulatory assets	1,570		1,556
Goodwill	4,005		4,005
Investments	159		158


Prepaid pension asset	187		199


Other	153		132
Total deferred debits and other assets	6,074		6,050
Total assets	$	30,317	$	29,715

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, 2026		December 31, 2025
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	612
Long-term debt due within one year	76		64
Accounts payable	715		816
Accrued expenses	378		359
Payables to affiliates	56		71
Borrowings from Exelon intercompany money pool	96		80

Customer deposits	135		123
Regulatory liabilities	170		103
Unamortized energy contract liabilities	4		5


Renewable energy credit obligations	192		223
Other	158		121
Total current liabilities	1,980		2,577
Long-term debt	10,058		9,526
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	3,524		3,391
Regulatory liabilities	716		722
Asset retirement obligations	56		62
Non-pension postretirement benefit obligations	15		24




Unamortized energy contract liabilities	13		16
Other	435		418
Total deferred credits and other liabilities	4,759		4,633
Total liabilities	16,797		16,736
Commitments and contingencies

Member's equity
Membership interest	13,616		13,130

Undistributed losses	(96)		(151)

Total member's equity	13,520		12,979
Total liabilities and member's equity	$	30,317	$	29,715

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, 2026
(In millions)	Membership Interest		Undistributed (Losses)/Gains		Total Member's Equity
Balance at December 31, 2025	$	13,130	$	(151)	$	12,979
Net income	—		169		169
Distributions to member	—		(139)		(139)
Contributions from member	275		—		275
Balance at March 31, 2026	$	13,405	$	(121)	$	13,284
Net income	—		109		109
Distributions to member	—		(108)		(108)
Contributions from member	131		—		131
Balance at June 30, 2026	$	13,536	$	(120)	$	13,416
Net income	—		187		187
Distributions to member	—		(163)		(163)
Contributions from member	80		—		80

Balance at September 30, 2026	$	13,616	$	(96)	$	13,520


	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

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)	2026		2025		2026		2025
Operating revenues
Electric operating revenues	$	1,123	$	995	$	2,981	$	2,641
Revenues from alternative revenue programs	1		(5)		(13)		(19)
Operating revenues from affiliates	3		2		7		4
Total operating revenues	1,127		992		2,975		2,626
Operating expenses
Purchased power	450		367		1,178		942

Operating and maintenance	294		95		564		282
Operating and maintenance from affiliates	60		59		198		184
Depreciation and amortization	115		110		343		321
Taxes other than income taxes	128		122		359		344
Total operating expenses	1,047		753		2,642		2,073

Gain on sale of assets	—		—		—		1

Operating income	80		239		333		554
Other income and (deductions)
Interest expense, net	(58)		(53)		(169)		(159)
Interest expense to affiliates, net	1		—		1		—
Other, net	13		11		37		31
Total other income and (deductions)	(44)		(42)		(131)		(128)
Income before income taxes	36		197		202		426
Income taxes	(4)		41		29		89

Net income	$	40	$	156	$	173	$	337










Comprehensive income	$	40	$	156	$	173	$	337

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)	2026		2025
Cash flows from operating activities
Net income	$	173	$	337
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion	343		322
Gain on sales of assets	—		(1)
Asset disallowances, impairments and write-off	195		—
Deferred income taxes and amortization of investment tax credits	(5)		34
Other non-cash operating activities	49		62
Changes in assets and liabilities:
Accounts receivable	(61)		(58)
Receivables from and payables to affiliates, net	(3)		—
Inventories	(13)		(11)
Accounts payable and accrued expenses	30		20
Collateral received, net	9		2
Income taxes	—		(27)
Regulatory assets and liabilities, net	14		(39)
Pension and non-pension postretirement benefit contributions	(7)		(7)
Other assets and liabilities	2		(5)
Net cash flows provided by operating activities	726		629
Cash flows from investing activities
Capital expenditures	(747)		(690)
Proceeds from sales of long-lived assets	—		2


Changes in PHI intercompany money pool	(24)		—
Other investing activities	3		—
Net cash flows used in investing activities	(768)		(688)
Cash flows from financing activities
Changes in short-term borrowings	(303)		(137)
Issuance of long-term debt	300		275


Dividends paid on common stock	(162)		(267)
Contributions from parent	278		192


Other financing activities	(8)		(8)
Net cash flows provided by financing activities	105		55
Increase (decrease) in cash, restricted cash, and cash equivalents	63		(4)
Cash, restricted cash, and cash equivalents at beginning of period	55		51
Cash, restricted cash, and cash equivalents at end of period	$	118	$	47

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(61)	$	(34)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Potomac Electric Power Company

Balance Sheets

(Unaudited)


(In millions)	September 30, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	79	$	22
Restricted cash and cash equivalents	39		33
Accounts receivable
Customer accounts receivable	527		484
Customer allowance for credit losses	(84)		(69)
Customer accounts receivable, net	443		415
Other accounts receivable	157		154
Other allowance for credit losses	(26)		(26)
Other accounts receivable, net	131		128


Receivable from PHI intercompany money pool	24		—

Inventories, net	187		174



Regulatory assets	160		182

Prepaid renewable energy credits	142		171
Other	25		59
Total current assets	1,230		1,184
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,995 and $4,784 as of September 30, 2026 and December 31, 2025, respectively)	10,977		10,747
Deferred debits and other assets
Regulatory assets	387		405
Investments	145		141



Prepaid pension asset	175		194

Other	70		57
Total deferred debits and other assets	777		797
Total assets	$	12,984	$	12,728

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Potomac Electric Power Company

Balance Sheets

(Unaudited)


(In millions)	September 30, 2026		December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	303
Long-term debt due within one year	7		6
Accounts payable	378		418
Accrued expenses	187		173
Payables to affiliates	34		37



Customer deposits	68		61
Regulatory liabilities	18		13


Renewable energy credit obligations	144		174
Other	85		84
Total current liabilities	921		1,269
Long-term debt	4,933		4,626

Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,636		1,604
Regulatory liabilities	262		268
Asset retirement obligations	38		45






Other	203		214
Total deferred credits and other liabilities	2,139		2,131
Total liabilities	7,993		8,026
Commitments and contingencies
Shareholder's equity
Common stock	3,806		3,528


Retained earnings	1,185		1,174

Total shareholder's equity	4,991		4,702
Total liabilities and shareholder's equity	$	12,984	$	12,728

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, 2026
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2025	$	3,528	$	1,174	$	4,702
Net income	—		68		68
Common stock dividends	—		(64)		(64)
Contributions from parent	139		—		139
Balance at March 31, 2026	$	3,667	$	1,178	$	4,845
Net income	—		65		65



Common stock dividends	—		(57)		(57)
Contributions from parent	131		—		131
Balance at June 30, 2026	$	3,798	$	1,186	$	4,984
Net income	—		40		40



Common stock dividends	—		(41)		(41)
Contributions from parent	8		—		8
Balance at September 30, 2026	$	3,806	$	1,185	$	4,991


	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

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)	2026		2025		2026		2025
Operating revenues
Electric operating revenues	$	516	$	467	$	1,436	$	1,316
Natural gas operating revenues	40		27		197		148
Revenues from alternative revenue programs	(3)		(5)		(8)		(10)
Operating revenues from affiliates	3		2		7		6
Total operating revenues	556		491		1,632		1,460
Operating expenses
Purchased power	245		211		655		580
Purchased fuel	19		8		92		57

Operating and maintenance	66		51		200		162
Operating and maintenance from affiliates	42		43		139		134
Depreciation and amortization	67		63		200		189
Taxes other than income taxes	16		21		66		63
Total operating expenses	455		397		1,352		1,185



Operating income	101		94		280		275
Other income and (deductions)
Interest expense, net	(28)		(26)		(81)		(75)

Other, net	7		4		14		12
Total other income and (deductions)	(21)		(22)		(67)		(63)
Income before income taxes	80		72		213		212
Income taxes	19		17		49		49

Net income	$	61	$	55	$	164	$	163
Comprehensive income	$	61	$	55	$	164	$	163

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)	2026		2025
Cash flows from operating activities
Net income	$	164	$	163
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	200		189

Deferred income taxes and amortization of investment tax credits	31		24

Other non-cash operating activities	42		42
Changes in assets and liabilities:
Accounts receivable	51		20
Receivables from and payables to affiliates, net	(6)		(3)
Inventories	(2)		(16)
Accounts payable and accrued expenses	(1)		15
Collateral paid, net	(1)		—
Income taxes	(7)		(1)
Regulatory assets and liabilities, net	1		(32)
Pension and non-pension postretirement benefit contributions	(1)		(1)
Other assets and liabilities	50		23
Net cash flows provided by operating activities	521		423
Cash flows from investing activities
Capital expenditures	(429)		(402)



Other investing activities	1		—
Net cash flows used in investing activities	(428)		(402)
Cash flows from financing activities
Changes in short-term borrowings	(161)		(111)
Issuance of long-term debt	150		125


Dividends paid on common stock	(119)		(149)
Contributions from parent	113		107
Other financing activities	(7)		(8)
Net cash flows used in financing activities	(24)		(36)
Increase (decrease) in cash, restricted cash, and cash equivalents	69		(15)
Cash, restricted cash, and cash equivalents at beginning of period	12		23
Cash, restricted cash, and cash equivalents at end of period	$	81	$	8

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(37)	$	(40)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Delmarva Power & Light Company

Balance Sheets

(Unaudited)


(In millions)	September 30, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	79	$	9
Restricted cash and cash equivalents	2		3
Accounts receivable
Customer accounts receivable	194		253
Customer allowance for credit losses	(21)		(19)
Customer accounts receivable, net	173		234
Other accounts receivable	73		75
Other allowance for credit losses	(11)		(10)
Other accounts receivable, net	62		65
Receivables from affiliates	6		2

Inventories, net
Fossil fuel	10		9
Materials and supplies	108		107
Prepaid utility taxes	7		29

Regulatory assets	76		72
Prepaid renewable energy credits	24		30
Other	13		13
Total current assets	560		573
Property, plant, and equipment (net of accumulated depreciation and amortization of $2,367 and $2,241 as of September 30, 2026 and December 31, 2025, respectively)	6,066		5,855
Deferred debits and other assets
Regulatory assets	218		214



Other	137		147
Total deferred debits and other assets	355		361
Total assets	$	6,981	$	6,789

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Delmarva Power & Light Company

Balance Sheets

(Unaudited)


(In millions)	September 30, 2026		December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	161
Long-term debt due within one year	63		53
Accounts payable	164		218
Accrued expenses	82		70
Payables to affiliates	23		25

Customer deposits	40		36
Regulatory liabilities	49		42
Renewable energy credit obligations	48		49
Other	23		22
Total current liabilities	492		676
Long-term debt	2,435		2,291
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,040		996
Regulatory liabilities	323		316
Asset retirement obligations	13		12


Other	149		127
Total deferred credits and other liabilities	1,525		1,451
Total liabilities	4,452		4,418
Commitments and contingencies
Shareholder's equity
Common stock	1,835		1,722

Retained earnings	694		649
Total shareholder's equity	2,529		2,371
Total liabilities and shareholder's equity	$	6,981	$	6,789

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, 2026
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2025	$	1,722	$	649	$	2,371
Net income	—		77		77
Common stock dividends	—		(50)		(50)
Contributions from parent	45		—		45
Balance at March 31, 2026	$	1,767	$	676	$	2,443
Net income	—		26		26
Common stock dividends	—		(36)		(36)
Contributions from parent	—		—		—
Balance at June 30, 2026	$	1,767	$	666	$	2,433
Net income	—		61		61
Common stock dividends	—		(33)		(33)
Contributions from parent	68		—		68
Balance at September 30, 2026	$	1,835	$	694	$	2,529


	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

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)	2026		2025		2026		2025
Operating revenues
Electric operating revenues	$	579	$	553	$	1,428	$	1,323
Revenues from alternative revenue programs	(1)		16		(30)		2
Operating revenues from affiliates	1		1		4		3
Total operating revenues	579		570		1,402		1,328
Operating expenses
Purchased power	276		286		668		616

Operating and maintenance	61		55		166		161
Operating and maintenance from affiliates	31		37		119		116
Depreciation and amortization	67		61		195		188
Taxes other than income taxes	2		2		8		7
Total operating expenses	437		441		1,156		1,088



Operating income	142		129		246		240
Other income and (deductions)
Interest expense, net	(23)		(20)		(67)		(62)

Other, net	3		2		8		8
Total other income and (deductions)	(20)		(18)		(59)		(54)
Income before income taxes	122		111		187		186
Income taxes	32		29		48		48

Net income	$	90	$	82	$	139	$	138
Comprehensive income	$	90	$	82	$	139	$	138

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Atlantic City Electric Company and Subsidiary Company

Consolidated Statements Of Cash Flows

(Unaudited)


	Nine Months Ended September 30,
(In millions)	2026		2025
Cash flows from operating activities
Net income	$	139	$	138
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	195		188

Deferred income taxes and amortization of investment tax credits	52		32
Other non-cash operating activities	65		42
Changes in assets and liabilities:
Accounts receivable	(41)		9
Receivables from and payables to affiliates, net	5		(8)
Inventories	(3)		(10)
Accounts payable and accrued expenses	(4)		5
Collateral received, net	30		—
Income taxes	1		3
Regulatory assets and liabilities, net	(30)		(14)
Pension and non-pension postretirement benefit contributions	(15)		(3)
Other assets and liabilities	4		(21)
Net cash flows provided by operating activities	398		361
Cash flows from investing activities
Capital expenditures	(339)		(292)


Other investing activities	1		—
Net cash flows used in investing activities	(338)		(292)
Cash flows from financing activities
Changes in short-term borrowings	(148)		(116)


Issuance of long-term debt	100		100

Changes in PHI intercompany money pool	24		—
Dividends paid on common stock	(129)		(132)
Contributions from parent	93		98
Other financing activities	(5)		(5)
Net cash flows used in financing activities	(65)		(55)
(Decrease) increase in cash, restricted cash, and cash equivalents	(5)		14
Cash, restricted cash, and cash equivalents at beginning of period	24		14
Cash, restricted cash, and cash equivalents at end of period	$	19	$	28

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(35)	$	(19)

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, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	15	$	22
Restricted cash and cash equivalents	4		2
Accounts receivable
Customer accounts receivable	256		239
Customer allowance for credit losses	(31)		(27)
Customer accounts receivable, net	225		212
Other accounts receivable	86		64
Other allowance for credit losses	(14)		(13)
Other accounts receivable, net	72		51

Receivables from affiliates	1		12

Inventories, net	79		76


Prepaid utility taxes	14		—
Regulatory assets	70		93
Other	8		8
Total current assets	488		476
Property, plant, and equipment (net of accumulated depreciation and amortization of $2,088 and $1,956 as of September 30, 2026 and December 31, 2025, respectively)	4,683		4,556
Deferred debits and other assets
Regulatory assets	608		559





Other	55		41
Total deferred debits and other assets	663		600
Total assets	$	5,834	$	5,632

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, 2026		December 31, 2025
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	148
Long-term debt due within one year	5		5
Accounts payable	161		168
Accrued expenses	55		64
Payables to affiliates	18		24


Borrowings from PHI intercompany money pool	24		—
Customer deposits	27		26
Regulatory liabilities	103		48
Other	46		13
Total current liabilities	439		496
Long-term debt	2,131		2,028
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	927		869
Regulatory liabilities	130		137






Other	76		74
Total deferred credits and other liabilities	1,133		1,080
Total liabilities	3,703		3,604
Commitments and contingencies
Shareholder's equity
Common stock	2,106		2,013
Retained earnings	25		15

Total shareholder's equity	2,131		2,028
Total liabilities and shareholder's equity	$	5,834	$	5,632

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, 2026
(In millions)	Common Stock		Retained (Deficit) Earnings		Total Shareholder's Equity
Balance at December 31, 2025	$	2,013	$	15	$	2,028
Net income	—		27		27
Common stock dividends	—		(25)		(25)
Contributions from parent	91		—		91
Balance at March 31, 2026	$	2,104	$	17	$	2,121
Net income	—		22		22
Common stock dividends	—		(15)		(15)
Contributions from parent	—		—		—
Balance at June 30, 2026	$	2,104	$	24	$	2,128
Net income	—		90		90
Common stock dividends	—		(89)		(89)
Contributions from parent	2		—		2
Balance at September 30, 2026	$	2,106	$	25	$	2,131


	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

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 (and, through its subsidiary, Commonwealth Edison Company of Indiana, transmission of electricity in a small portion of northwestern Indiana)

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

Prior Period Adjustments (ACE)

In the first quarter of 2026, management identified an error in the historical rate classification for a limited number of ACE customers that resulted in the overstatement of Regulatory assets and Revenues from alternative revenue programs. Management has concluded that the error was not material to previously issued or to the current period financial statements.

The impact of the error correction recognized in the first quarter of 2026 was a $14 million decrease to ACE’s Revenues from alternative revenue programs, a $4 million decrease to Income taxes, and a corresponding decrease of $14 million in Regulatory assets. The overall impact on ACE’s Operating income was a decrease of $14 million, and the impact on ACE’s Net income was $10 million. The error did not impact any net cash flow subtotal for the three months ended March 31, 2026.

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

Table of Contents

Combined Notes to Consolidated Financial Statements

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

Note 1 — Significant Accounting Policies

PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

The accompanying consolidated financial statements as of September 30, 2026 and for the three and nine months ended September 30, 2026 and 2025 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, 2025 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, 2026. 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, 2026: 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, 2026. 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.

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 for annual reporting periods beginning January 1, 2027, and for interim reporting periods within annual reporting periods beginning January 1, 2028. Early adoption is permitted. Exelon will adopt the guidance upon the applicable effective dates.

Environmental Credits and Environmental Credit Obligations (Issued May 2026). Establishes guidance for the recognition, measurement, presentation and disclosure of environmental credits and compliance obligations that may be settled by using environmental credits. The guidance is effective for annual and interim periods beginning January 1, 2028 with early adoption permitted. The guidance is adopted on a retrospective basis by recognizing a cumulative effect adjustment to retained earnings at the date of initial application.

2. Regulatory Matters (All Registrants)

As discussed in Note 2 — Regulatory Matters of the 2025 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2026 and updates to the 2025 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 2026.

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
	October 14, 2025 (amended April 16, 2026)	Electric	$	120	$	51	9.40%	August 28, 2026	August 10, 2026
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
	September 20, 2024 (amended September 5, 2025)	Natural Gas	$	37	$	22	9.60%	December 17, 2025	January 1, 2026
ACE - New Jersey	November 21, 2024	Electric	$	109	$	54	9.60%	November 21, 2025	December 1, 2025

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

DPL - Delaware(a)

December 9, 2025 (amended August 31, 2026)

Electric

10.50%

Third quarter of 2027

BGE - Maryland

July 2, 2026
(amended October 16, 2026)

Electric

151

10.40%

First quarter of 2027

__________

(a)DPL implemented interim rates on July 9, 2026, subject to refund.

ComEd Distribution Base Rate Case Proceedings

The ICC approved ComEd's four-year MRP for the period January 1, 2024 through 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 December 18, 2025, the ICC approved ComEd's 2024 MRP Reconciliation reflecting a revenue increase of $243 million, including the tax benefit of NOLCs. While NOLCs are included in the MRP Reconciliation per the final order, the impacts of the NOLCs will not be reflected in the financial statements until the PLR is received from the IRS. See Note 7 — Income Taxes for additional information on NOLCs.

On March 20, 2026, ComEd filed its annual revenue balancing reconciliation for 2025. The July 16, 2026 order approved the reconciliation, which is a component of revenue decoupling, reflecting a revenue reduction of $128 million. The reconciliation is effective January 1, 2027.

On May 1, 2026, ComEd filed its 2025 MRP Reconciliation reflecting a revenue increase of $234 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 7 — Income Taxes for additional information on NOLCs. On October 1, 2026, ComEd filed an agreed draft proposed order in the proceeding reflecting a proposed revenue increase of approximately $205 million, including the tax benefit of NOLCs. A final order must be issued by December 20, 2026.

PECO Distribution Base Rate Case Proceedings

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.

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.

BGE Distribution Base Rate Case Proceedings

In February 2023, BGE filed its three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 to the MDPSC, which was approved in December 2023 and went into effect on January 1, 2024. The MDSPC awarded BGE electric revenue requirement increases of $41 million, $113 million, and $25 million with an approved ROE of 9.50% in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $126 million, $62 million, and $41 million with an approved ROE of 9.45% in 2024, 2025, and 2026, respectively. The requested revenue requirement increases will be used to recover capital investments designed

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

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 were recovered through separate electric and gas riders between March 2024 and February 2025. As such, the reconciliation amounts are not included in the approved revenue 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. In December 2025, the MDPSC authorized BGE to recover $31 million and $46 million for electric and gas, respectively, beginning in February 2026 and extending through December 2027, in the reconciliation rider. In addition to the amounts approved in the reconciliation rider, the MDPSC provided for additional regulatory assets related to minor storms of $24 million (to be recovered over 5 years) and the Baltimore City conduit of $4 million. Recovery of these two regulatory assets was requested in BGE's recent MDPSC rate case filing submitted on July 2, 2026.

Pepco District of Columbia Distribution Base Rate Case Proceedings

On April 13, 2023, Pepco filed an electric base rate case with the DCPSC (amended February 27, 2024) requesting a total revenue requirement increase of $186 million and an ROE of 10.50%. The DCPSC issued an order approving the two-year cumulative multi-year plan on November 26, 2024, which included a total revenue requirement increase of $123 million with an ROE of 9.50% effective January 1, 2025. The DCPSC approved Pepco's electric incremental revenue requirement increases of $99 million and $24 million for 2025 and 2026, respectively. Subsequent to DCPSC approval of the order, interveners appealed the order on several grounds including that the DCPSC did not hold evidentiary hearings. On March 5, 2026, the District of Columbia Court of Appeals remanded the November 26, 2024, order back to the DCPSC to hold evidentiary hearings. On May 8, 2026, the DCPSC issued an order adopting a revised procedural schedule which additionally reaffirmed that current rates should remain in effect during the remand period and refunds for previous amounts collected are not required at this time. On June 30, 2026, the Commission issued a subsequent order revising the procedural schedule to update the due date for final briefs and on October 2, 2026, the DCPSC rescheduled the evidentiary hearing to December 7-8, 2026. Pepco is preparing for the proceeding and will continue to monitor developments. On July 20, 2026, the District of Columbia Office of People’s Counsel (DCOPC) appealed to the District of Columbia Court of Appeals (Court) the DCPSC’s May 8, 2026 order specifying that current rates should remain in effect, as well as filed at the DCPSC a motion to stay that May 8 order, pending the Court’s review. The Court appeal and the motion to stay at the DCPSC remain pending.

Pepco Maryland Distribution Base Rate Case Proceedings

On May 16, 2023, Pepco filed an electric base rate case with the MDPSC (amended February 23, 2024) requesting a total revenue requirement increase of $111 million (before offsets) and an ROE of 10.50%. The MDPSC issued an order on June 10, 2024 awarding Pepco a one-year multi-year plan for April 1, 2024 through March 31, 2025 which included an incremental revenue requirement increase of $45 million and an ROE of 9.50%. 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 the reconciliation amounts of $31 million for the 12-month period ended March 31, 2024, with supporting testimony and schedules. On March 31, 2026, the MDPSC issued an order authorizing Pepco to recover approximately $13 million through the reconciliation rider. This will be recovered through rates between May 2026 through April 2027. Additionally, the order disallowed the recovery of various assets. The order resulted in the write off of $11 million of Regulatory assets and $15 million of Property, plant and equipment with a total of $26 million recorded in Operating and maintenance expense.

On October 14, 2025, Pepco filed an electric base rate case with the MDPSC (amended April 16, 2026) requesting a total revenue requirement increase of $120 million and an ROE of 10.50%. The MDPSC issued an order on August 28, 2026, awarding Pepco a total revenue requirement increase of $51 million and an ROE of

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

9.40%, effective August 10, 2026. Additionally, the order resulted in the write off of $180 million of Property, plant and equipment, which was recorded in Operating and maintenance expense.

DPL Maryland Distribution Base Rate Case Proceedings

On May 19, 2022, DPL filed an electric base rate case with the MDPSC requesting a total revenue requirement increase of $38 million based on an ROE of 10.25%. On December 14, 2022, the MDPSC issued an order awarding DPL a total revenue requirement increase of $29 million with an ROE of 9.60%. The order reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025, with rates remaining in effect subsequent to the multi-year plan period. The MDPSC awarded DPL electric incremental revenue requirement increases of $17 million, $6 million, and $6 million for 2023, 2024, and 2025, respectively.

DPL Delaware Distribution Base Rate Case Proceedings

On December 15, 2022, DPL filed an electric base rate case with the DEPSC (amended September 29, 2023) requesting a total revenue requirement increase of $39 million and an ROE of 10.50%. On April 18, 2024, the DEPSC issued an order awarding DPL a total revenue requirement increase of $28 million with an ROE of 9.60%, effective July 15, 2023. As part of the approved order, 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.

ACE New Jersey Distribution Base Rate Case Proceedings

On November 21, 2024, ACE filed an electric base rate case with the NJBPU requesting a total revenue requirement increase of $109 million, before NJ sales and use tax, and an ROE of 10.70%. On November 21, 2025, the NJBPU issued an order awarding ACE an electric revenue requirement increase, before NJ sales and use tax, of $54 million effective December 1, 2025, with an ROE of 9.60%. In addition, the NJBPU approved the recovery through a regulatory asset of work stoppage costs that were incurred by ACE in 2023 of $38 million.

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 annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for ComEd, PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).

For 2026, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:


Registrant(a)	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation (Decrease) Increase		Total Revenue Requirement (Decrease) Increase(b)			Allowed Return on Rate Base(c)		Allowed ROE(d)
ComEd	$	31	$	(52)	$	(21)		8.15	%	11.50	%
PECO	$	20	$	20	$	40		7.62	%	10.35	%
BGE	$	16	$	(40)	$	(30)	(e)	7.51	%	10.50	%
Pepco	$	12	$	(21)	$	(9)		7.72	%	10.50	%
DPL	$	3	$	1	$	4		7.53	%	10.50	%
ACE	$	1	$	16	$	17		7.26	%	10.50	%

__________

(a)All rates are effective June 1, 2026 - May 31, 2027, 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 7 — Income Taxes for additional information on NOLCs.

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

(d)The rate of return on common equity for each Utility Registrant includes a 50-basis-point incentive adder for being a voluntary member of an RTO. Recently passed legislation in Maryland and New Jersey requires utilities to become a member of an RTO.

(e)The decrease in BGE's transmission revenue requirement includes a $6 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 (2024-2027 Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the MRP are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

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 2024-2027 Grid Plan as non-compliant with certain requirements of CEJA and required ComEd to file a revised 2024-2027 Grid Plan. On January 10, 2024, ComEd filed an appeal in the Illinois Appellate Court of portions of the ICC's December 2023 order, including but not limited to the allowed ROE, 50% equity ratio, and denial of a return on ComEd’s pension asset. On March 13, 2024, ComEd filed its Refiled 2024-2027 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 2024-2027 Grid Plan. On December 19, 2024, the ICC approved the Refiled 2024-2027 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. On September 30, 2026, the Illinois Appellate Court affirmed the ICC's decision on the appealed issues.

On January 16, 2026, ComEd filed a multi-year integrated grid plan (2028-2031 Grid Plan), seeking approval for planned investments on the electric distribution system within ComEd's service area in 2028-2031. The ICC must issue an order by December 15, 2026.

Carbon Mitigation Credit

CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear 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. On October 31, 2025, the seller provided notification to ComEd and the IPA that it has reflected on its 2024 federal tax return $804 million of nuclear production tax credits associated with its participating nuclear power generating facilities. These amounts were collected from the seller through an adjustment to the CMC price paid by ComEd and returned to customers in 2026. As of December 31, 2025, Exelon and ComEd's Consolidated Balance Sheets reflected these amounts as a receivable from the seller with an offsetting balance within the Carbon mitigation credit regulatory liability. These adjustments had no net impact on Exelon and ComEd’s Consolidated Statements of Operations and Comprehensive Income. 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 or liability is recorded for the difference between ComEd's costs associated with the procurement of CMCs from participating nuclear power generating facilities and revenues received from customers. The balance of the asset as of September 30, 2026 is $9 million.

On October 20, 2026, the seller provided notification to ComEd and the IPA that it has reflected on its 2025 federal income tax return $155 million of nuclear production tax credits associated with its participating nuclear power generating facilities. These amounts will be collected from the seller through an adjustment to the CMC price to be paid by ComEd and returned to customers in 2027. In the fourth quarter of 2026, Exelon and ComEd's Consolidated Balance Sheets will reflect these additional 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

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

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). In 2026, Illinois enacted the CRGA, which makes certain changes to the energy efficiency framework established under CEJA.

CRGA modifies the manner in which ComEd’s energy efficiency savings goals are calculated by establishing a flat incremental annual savings requirement that applies indefinitely. CRGA also increases energy efficiency budget and low‑income commitments from levels established under CEJA, expands the categories of savings that may be credited toward annual goals, and revises the return on equity applicable to the energy efficiency regulatory asset to align with the distribution return on equity.

ComEd filed its annual energy efficiency formula rate update with the ICC on May 29, 2026. The filing establishes the revenue requirement used to set the rates that will take effect in January 2027, subject to the ICC's review and approval. The requested revenue requirement update is based on a reconciliation of the 2025 actual costs plus projected 2027 expenditures.


Initial Revenue Requirement Increase		Annual Reconciliation Decrease		Total Revenue Requirement Decrease		Requested Return on Rate Base(a)		Requested ROE
$	28	$	(56)	$	(28)	6.62	%	8.905	%

__________

(a)The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.62% inclusive of an allowed ROE of 8.905%. For the 2025 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 7.67% inclusive of an allowed ROE of 11.0%, 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.

Beginning in 2027, ComEd expects that implementation of CRGA may result in higher annual energy efficiency spending. Incremental costs incurred in advance of recovery are expected to be deferred as a regulatory asset and recovered through ComEd’s energy efficiency formula rate over the weighted‑average useful life of the related measures, subject to approval by the Illinois Commerce Commission.

Maryland Regulatory Matters

Summer and Winter Rate Mitigation (Exelon, BGE, PHI, Pepco, and DPL). As part of the passing of the Next Generation Energy Act of 2025 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 were distributed to residential customers based on their consumption of electricity supply that was 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 February 3, 2026. These amounts were used to reduce residential customer account receivable balances within the first quarter of 2026.

Maryland Utility Relief Act (Exelon, BGE, PHI, Pepco, and DPL). On May 12, 2026, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including a moratorium on rate cases with forecasted test years until April 1, 2027. Additionally, BGE, Pepco and DPL are required to participate as a member in an RTO effective July 1, 2026, which resulted in a complaint filed on July

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

2, 2026 against Maryland Transmission Operators, including BGE, Pepco, and DPL, at FERC for the removal of the 50-basis-point incentive adder in the transmission formula rates. The final outcome and resolution of the complaint filing cannot be predicted and the results are not expected to be material to Exelon, BGE, PHI, Pepco, and DPL financial statements.

Delaware Regulatory Matters

Delaware Senate Bill 326 (Exelon, PHI, and DPL). On July 13, 2026, the Governor of Delaware signed into law legislation that addresses several matters pertaining to public utility companies. As part of the law, DPL’s non-mandatory capital spend eligible to be recovered in rates will be limited to $70 million in each of the years ended 2026 and 2027 unless the spend falls within an exception or the commission orders otherwise. Further, beginning in 2028, DPL’s non-mandatory capital spend eligible to be recovered in rates shall not exceed 5% of DPL’s rate base approved in its most recent base rate case. The legislation also modifies the timing of interim rate recovery in base rate case proceedings. If the DEPSC has not issued a decision within 7 months of a filing, DPL may implement 50% of the proposed rate increase, subject to refund. If no decision has been issued after 12 months, DPL may implement 75% of the proposed increase, also subject to refund. DPL is continuing to evaluate the overall potential impacts of the legislation and will continue to monitor related regulatory developments.

New Jersey Regulatory Matters

New Jersey Repeal RTO Adder Bill (Exelon, PHI, and ACE). On July 7, 2026, the Governor of New Jersey signed into law legislation that addresses several matters pertaining to electric utility companies. As part of the legislation ACE is required to participate as a member in an RTO effective January 1, 2027, which could result in a complaint filed for the removal of the 50-basis-point incentive adder in the transmission formula rates.

Other Federal Regulatory Matters

PJM Cost Allocation Methodology (All Registrants). On October 7, 2026, FERC issued an order providing additional direction on its March 6, 2026 order. The March 6, 2026, order required PJM to eliminate the de minimis threshold exemption used to allocate certain transmission reliability upgrade costs to the rate zones of PJM Transmission Owners, including the Utility Registrants. FERC also directed PJM to recalculate historical cost allocations beginning June 18, 2015, and, as applicable, pass through additional charges or payments to PJM customers, including the Utility Registrants, as applicable, with interest. The October 7th order also directed that hearing and settlement proceedings be held to determine how PJM should reflect changes in market participants during the 15-year refund and surcharge period. An appeal of FERC's March 6th order remains pending before the United States Court of Appeals for the D.C. Circuit.

The final impact of these proceedings cannot be predicted or reasonably estimated at this time, but could be material to the financial statements.

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2025, unless noted below. See Note 2 — Regulatory Matters of the 2025 Form 10-K for additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets increased $290 million primarily due to an increase of $137 million in the regulatory asset for Electric distribution significant one-time events, primarily related to storm costs. Regulatory liabilities decreased $86 million primarily due to a decrease of $670 million in the Carbon mitigation credit regulatory liability, partially offset by an increase of $285 million in the Decommissioning the Regulatory Agreement Units regulatory liability and an increase of $159 million in the Renewable portfolio standards costs regulatory liability.

PECO. Regulatory assets increased $194 million primarily due to an increase of $148 million in the Deferred income taxes regulatory asset. Regulatory liabilities increased $144 million primarily due to an increase of $156 million in the Decommissioning the Regulatory Agreement Units.

BGE. Regulatory assets decreased $99 million primarily due to a decrease of $62 million in the Energy efficiency and demand response programs regulatory asset and a decrease of $47 million in the Electric energy and natural gas costs regulatory asset. Regulatory liabilities decreased $25 million primarily due to a decrease of $47 million in the Deferred income taxes regulatory liability.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 2 — Regulatory Matters

Pepco. Regulatory assets decreased $40 million primarily due to a decrease of $47 million in the Energy efficiency and demand response programs regulatory asset. Regulatory liabilities decreased $1 million primarily due to a decrease of $36 million in the Deferred income taxes regulatory liability, partially offset by an increase of $22 million in the Removal costs regulatory liability.

DPL. Regulatory assets increased $8 million primarily due to an increase of $13 million in the Removal costs regulatory asset and an increase of $8 million in the Electric energy and natural gas costs regulatory asset, partially offset by a decrease of $21 million in the Energy efficiency and demand response costs regulatory asset.

ACE. Regulatory assets increased $26 million primarily due to an increase of $58 million in the Energy efficiency and demand response programs regulatory asset. Regulatory liabilities increased $48 million primarily due to an increase of $30 million in the Electric energy and natural gas costs regulatory liability and an increase of $24 million in the Zero emissions credit regulatory liability, partially offset by a decrease of $11 million in the Transmission formula rate annual reconciliations 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, 2026 and December 31, 2025.


	Exelon		ComEd(a)		BGE(b)		PHI		Pepco(c)		DPL(d)		ACE(e)
September 30, 2026	$	67	$	10	$	31	$	26	$	11	$	—	$	15

December 31, 2025	98		12		47		39		22		1		16

__________

(a)For the nine months ended September 30, 2026, reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rate, distributed generation, and energy efficiency regulatory assets. For the year ended December 31, 2025, reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution rates and distributed generation regulatory assets.

(b)BGE's amount capitalized for ratemaking purposes primarily relates to 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.

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 3 — Revenue from Contracts with Customers of the 2025 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 3 —

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

Revenue from Contracts with Customers of the 2025 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, 2026 and 2025. At September 30, 2026 and December 31, 2025, ComEd's, PECO's, and BGE's contract liabilities were immaterial.



	Exelon(a)		PHI(a)		Pepco(a)		DPL(a)		ACE
Balance at December 31, 2025	$	119	$	119	$	95	$	12	$	12
Revenues recognized	(1)		(1)		(1)		—		—
Balance at March 31, 2026	$	118	$	118	$	94	$	12	$	12
Revenues recognized	(1)		(1)		(1)		—		—
Balance at June 30, 2026	$	117	$	117	$	93	$	12	$	12
Revenues recognized	(2)		(2)		(2)		—		—
Balance at September 30, 2026	$	115	$	115	$	91	$	12	$	12

	Exelon(a)		PHI(a)		Pepco(a)		DPL(a)		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

__________

(a)Revenues recognized in the three and nine months ended September 30, 2026 and 2025, were included in the contract liabilities at December 31, 2025 and 2024, 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, 2026. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.

This disclosure excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure. This disclosure also excludes transmission service agreements as the total consideration is not fixed and determinable at contract inception.


Year	Exelon		PHI		Pepco		DPL		ACE
2026	$	1	$	1	$	1	$	—	$	—
2027	6		6		5		1		—
2028	6		6		5		—		1
2029	7		7		6		1		—
2030 and thereafter	95		95		74		10		11
Total	$	115	$	115	$	91	$	12	$	12

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.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information

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. The CODMs of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE 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, 2026 and 2025 is as follows:

Three Months Ended September 30, 2026 and 2025



	ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2026
Electric revenues	$	2,470	$	1,155	$	1,247	$	2,215	$	—	$	(8)	$	7,079
Natural gas revenues	—		85		116		40		—		(1)		240
Shared service and other revenues	—		—		—		5		470		(475)		—
Total operating revenues	$	2,470	$	1,240	$	1,363	$	2,260	$	470	$	(484)	$	7,319
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
Less:
Purchased power
2026	$	783	$	475	$	636	$	971	$	—	$	—	$	2,865
2025	806		428		547		864		—		—		2,645
Purchased fuel
2026	$	—	$	19	$	14	$	19	$	—	$	—	$	52
2025	—		18		21		8		—		—		47



Operating and maintenance
2026	$	359	$	258	$	236	$	510	$	428	$	(227)	$	1,564
2025	313		183		179		290		409		(202)		1,172
Operating and maintenance from affiliates
2026	$	105	$	55	$	56	$	39	$	12	$	(267)	$	—
2025	96		58		60		45		11		(270)		—
Depreciation and amortization
2026	$	438	$	126	$	161	$	250	$	16	$	—	$	991

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	395		115		155		234		13		—		912
Taxes other than income taxes
2026	$	133	$	73	$	100	$	150	$	12	$	—	$	468
2025	107		69		93		150		10		—		429



Interest expense, net(c)
2026	$	146	$	74	$	73	$	110	$	184	$	—	$	587
2025	132		63		64		102		170		—		531
Interest expense to affiliates, net(c)
2026	$	3	$	2	$	—	$	1	$	—	$	—	$	6
2025	3		2		—		—		—		2		7
Other, net
2026	$	(43)	$	(15)	$	(26)	$	(23)	$	(2)	$	12	$	(97)
2025	(33)		(11)		(15)		(18)		(4)		13		(68)
Income Taxes
2026	$	140	$	8	$	23	$	46	$	(62)	$	(1)	$	154
2025	83		5		23		85		(41)		—		155
Net income (loss) attributable to common shareholders
2026	$	406	$	165	$	90	$	187	$	(118)	$	(1)	$	729
2025	373		250		82		291		(121)		—		875
Supplemental segment information
Intersegment revenues(d)
2026	$	2	$	5	$	2	$	5	$	465	$	(479)	$	—
2025	2		3		2		2		444		(453)		—
Capital Expenditures
2026	$	851	$	505	$	402	$	461	$	24	$	—	$	2,243
2025	781		502		407		444		2		—		2,136

__________

(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 15 — 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 16 — Related Party Transactions for additional information on intersegment revenues.

PHI:



	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2026
Electric revenues	$	1,127	$	516	$	579	$	—	$	(7)	$	2,215
Natural gas revenues	—		40		—		—		—		40
Shared service and other revenues	—		—		—		105		(100)		5
Total operating revenues	$	1,127	$	556	$	579	$	105	$	(107)	$	2,260
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
Less:
Purchased power

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information


2026	$	450	$	245	$	276	$	—	$	—	$	971
2025	367		211		286		—		—		864
Purchased fuel
2026	$	—	$	19	$	—	$	—	$	—	$	19
2025	—		8		—		—		—		8



Operating and maintenance
2026	$	294	$	66	$	61	$	89	$	—	$	510
2025	95		51		55		89		—		290
Operating and maintenance from affiliates
2026	$	60	$	42	$	31	$	14	$	(108)	$	39
2025	59		43		37		14		(108)		45
Depreciation and amortization
2026	$	115	$	67	$	67	$	1	$	—	$	250
2025	110		63		61		—		—		234
Taxes other than income taxes
2026	$	128	$	16	$	2	$	4	$	—	$	150
2025	122		21		2		5		—		150



Interest expense, net(c)
2026	$	58	$	28	$	23	$	1	$	—	$	110
2025	53		26		20		3		—		102
Interest expense to affiliates, net(c)
2026	$	(1)	$	—	$	—	$	1	$	1	$	1
2025	—		—		—		1		(1)		—
Other, net
2026	$	(13)	$	(7)	$	(3)	$	—	$	—	$	(23)
2025	(11)		(4)		(2)		(1)		—		(18)
Income Taxes
2026	$	(4)	$	19	$	32	$	(1)	$	—	$	46
2025	41		17		29		(2)		—		85
Net income (loss) attributable to common shareholders
2026	$	40	$	61	$	90	$	(4)	$	—	$	187
2025	156		55		82		(2)		—		291
Supplemental segment information
Intersegment revenues(d)
2026	$	3	$	3	$	1	$	105	$	(107)	$	5
2025	2		2		1		106		(109)		2
Capital Expenditures
2026	$	231	$	129	$	99	$	2	$	—	$	461
2025	221		125		96		2		—		444

__________

(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):

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information

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



	Three Months Ended September 30, 2026
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	1,377	$	796	$	795	$	1,283	$	583	$	319	$	381
Small commercial & industrial	621		173		130		230		60		81		89
Large commercial & industrial	184		82		200		445		370		34		41
Public authorities & electric railroads	12		8		8		20		11		4		5
Other(a)	280		89		115		241		99		80		64
Total electric revenues(b)	$	2,474	$	1,148	$	1,248	$	2,219	$	1,123	$	518	$	580
Natural gas revenues
Residential	$	—	$	54	$	67	$	15	$	—	$	15	$	—
Small commercial & industrial	—		20		14		8		—		8		—
Large commercial & industrial	—		—		41		1		—		1		—
Transportation	—		9		—		5		—		5		—
Other(c)	—		2		6		11		—		11		—
Total natural gas revenues(d)	$	—	$	85	$	128	$	40	$	—	$	40	$	—
Total revenues from contracts with customers	$	2,474	$	1,233	$	1,376	$	2,259	$	1,123	$	558	$	580
Other revenues
Revenues from alternative revenue programs	$	(15)	$	1	$	(18)	$	(3)	$	1	$	(3)	$	(1)
Other electric revenues(e)	11		6		5		4		3		1		—
Other natural gas revenues(e)	—		—		—		—		—		—		—

Total other revenues	$	(4)	$	7	$	(13)	$	1	$	4	$	(2)	$	(1)
Total revenues for reportable segments	$	2,470	$	1,240	$	1,363	$	2,260	$	1,127	$	556	$	579

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

__________

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

(b)Includes operating revenues from affiliates in 2026 and 2025 respectively of:

•$2 million, $2 million at ComEd

•$4 million, $2 million at PECO

•$1 million, $1 million at BGE

•$5 million, $2 million at PHI

•$3 million, $2 million at Pepco

•$3 million, $2 million at DPL

•$1 million, $1 million at ACE

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

(d)Includes operating revenues from affiliates in 2026 and 2025 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, 2026 and 2025


	ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2026
Electric revenues	$	6,368	$	3,178	$	3,543	$	5,795	$	—	$	(32)	$	18,852
Natural gas revenues	—		616		866		197		—		(3)		1,676
Shared service and other revenues	—		—		—		10		1,429		(1,439)		—
Total operating revenues	$	6,368	$	3,794	$	4,409	$	6,002	$	1,429	$	(1,474)	$	20,528

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
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
Less:
Purchased power
2026	$	1,814	$	1,278	$	1,787	$	2,501	$	—	$	—	$	7,380
2025	2,044		1,093		1,365		2,138		—		—		6,640
Purchased fuel
2026	$	—	$	217	$	215	$	92	$	—	$	—	$	524
2025	—		195		219		57		—		—		471



Operating and maintenance
2026	$	1,033	$	760	$	716	$	1,212	$	1,308	$	(613)	$	4,416
2025	958		690		621		876		1,313		(618)		3,840
Operating and maintenance from affiliates
2026	$	317	$	189	$	194	$	157	$	37	$	(894)	$	—
2025	296		182		186		148		32		(844)		—
Depreciation and amortization
2026	$	1,258	$	373	$	496	$	741	$	42	$	—	$	2,910

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	1,162		336		473		701		45		—		2,717
Taxes other than income taxes
2026	$	345	$	204	$	301	$	445	$	40	$	—	$	1,335
2025	303		183		273		426		31		—		1,216
(Gain) on sale of assets
2026	$	—	$	—	$	—	$	—	$	—	$	—	$	—
2025	—		—		—		(1)		—		—		(1)
Interest expense, net(c)
2026	$	418	$	213	$	202	$	323	$	546	$	—	$	1,702
2025	385		179		183		303		510		—		1,560
Interest expense to affiliates, net(c)
2026	$	10	$	6	$	—	$	3	$	—	$	—	$	19
2025	10		9		—		2		(1)		(2)		18
Other, net
2026	$	(116)	$	(39)	$	(64)	$	(62)	$	(8)	$	33	$	(256)
2025	(86)		(29)		(35)		(54)		(22)		41		(185)
Income taxes
2026	$	324	$	31	$	119	$	125	$	(145)	$	—	$	454
2025	201		23		108		184		(120)		—		396
Net income (loss) attributable to common shareholders
2026	$	965	$	562	$	443	$	465	$	(391)	$	—	$	2,044
2025	903		652		398		628		(407)		—		2,174
Supplemental segment information
Intersegment revenues(d)
2026	$	15	$	13	$	7	$	10	$	1,419	$	(1,464)	$	—
2025	19		9		6		7		1,374		(1,415)		—
Capital expenditures
2026	$	2,522	$	1,469	$	1,224	$	1,521	$	63	$	—	$	6,799
2025	1,970		1,334		1,211		1,552		28		—		6,095
Total assets
September 30, 2026	$	50,538	$	21,314	$	18,441	$	30,317	$	5,762	$	(4,135)	$	122,237
December 31, 2025	48,285		19,362		17,184		29,715		6,170		(4,146)		116,570

__________

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

PHI:


	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2026
Electric revenues	$	2,975	$	1,435	$	1,402	$	—	$	(17)	$	5,795
Natural gas revenues	—		197		—		—		—		197

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 4 — Segment Information


Shared service and other revenues	—		—		—		335		(325)		10
Total operating revenues	$	2,975	$	1,632	$	1,402	$	335	$	(342)	$	6,002
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
Total operating revenues	$	2,626	$	1,460	$	1,328	$	323	$	(329)	$	5,408
Less:
Purchased power
2026	$	1,178	$	655	$	668	$	—	$	—	$	2,501
2025	942		580		616		—		—		2,138
Purchased fuel
2026	$	—	$	92	$	—	$	—	$	—	$	92
2025	—		57		—		—		—		57



Operating and maintenance
2026	$	564	$	200	$	166	$	282	$	—	$	1,212
2025	282		162		161		271		—		876
Operating and maintenance from affiliates
2026	$	198	$	139	$	119	$	43	$	(342)	$	157
2025	184		134		116		43		(329)		148
Depreciation and amortization
2026	$	343	$	200	$	195	$	3	$	—	$	741
2025	321		189		188		3		—		701
Taxes other than income taxes
2026	$	359	$	66	$	8	$	12	$	—	$	445
2025	344		63		7		12		—		426
(Gain) on sale of assets
2026	$	—	$	—	$	—	$	—	$	—	$	—
2025	(1)		—		—		—		—		(1)
Interest expense, net(c)
2026	$	169	$	81	$	67	$	6	$	—	$	323
2025	159		75		62		7		—		303
Interest expense to affiliates, net(c)
2026	$	(1)	$	—	$	—	$	3	$	1	$	3
2025	—		—		—		2		—		2
Other, net
2026	$	(37)	$	(14)	$	(8)	$	(2)	$	(1)	$	(62)
2025	(31)		(12)		(8)		(3)		—		(54)
Income taxes
2026	$	29	$	49	$	48	$	(1)	$	—	$	125
2025	89		49		48		(2)		—		184
Net income (loss) attributable to common shareholders
2026	$	173	$	164	$	139	$	(11)	$	—	$	465
2025	337		163		138		(10)		—		628
Supplemental segment information
Intersegment revenues(d)
2026	$	7	$	7	$	4	$	334	$	(342)	$	10
2025	4		6		3		323		(329)		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


Capital expenditures
2026	$	747	$	429	$	339	$	6	$	—	$	1,521
2025	690		402		292		168		—		1,552
Total assets
September 30, 2026	$	12,984	$	6,981	$	5,834	$	4,577	$	(59)	$	30,317
December 31, 2025	12,728		6,789		5,632		4,602		(36)		29,715

__________

(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, 2026
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	3,501	$	2,122	$	2,254	$	3,244	$	1,485	$	879	$	880
Small commercial & industrial	1,632		502		368		603		163		218		222
Large commercial & industrial	436		254		541		1,239		1,012		98		129
Public authorities & electric railroads	35		25		25		59		32		12		15
Other(a)	785		244		353		698		286		233		186
Total electric revenues(b)	$	6,389	$	3,147	$	3,541	$	5,843	$	2,978	$	1,440	$	1,432
Natural gas revenues
Residential	$	—	$	422	$	561	$	106	$	—	$	106	$	—
Small commercial & industrial	—		145		95		46		—		46		—
Large commercial & industrial	—		—		182		7		—		7		—
Transportation	—		35		—		15		—		15		—
Other(c)	—		12		42		23		—		23		—
Total natural gas revenues(d)	$	—	$	614	$	880	$	197	$	—	$	197	$	—
Total revenues from contracts with customers	$	6,389	$	3,761	$	4,421	$	6,040	$	2,978	$	1,637	$	1,432
Other revenues
Revenues from alternative revenue programs	$	(62)	$	10	$	(35)	$	(51)	$	(13)	$	(8)	$	(30)
Other electric revenues(e)	41		21		18		13		10		3		—
Other natural gas revenues(e)	—		2		5		—		—		—		—

Total other revenues	$	(21)	$	33	$	(12)	$	(38)	$	(3)	$	(5)	$	(30)
Total revenues for reportable segments	$	6,368	$	3,794	$	4,409	$	6,002	$	2,975	$	1,632	$	1,402

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, 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

__________

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

(b)Includes operating revenues from affiliates in 2026 and 2025 respectively of:

•$15 million, $19 million at ComEd

•$11 million, $7 million at PECO

•$5 million, $4 million at BGE

•$10 million, $7 million at PHI

•$7 million, $4 million at Pepco

•$7 million, $6 million at DPL

•$4 million, $3 million at ACE

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

(d)Includes operating revenues from affiliates in 2026 and 2025 respectively of:

•$2 million, $2 million at PECO

•$2 million, $2 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, 2026
	Exelon		ComEd(b)(c)		PECO		BGE(d)		PHI		Pepco(e)		DPL		ACE(e)(f)
Balance at June 30, 2026	$	508	$	102	$	142	$	136	$	128	$	77	$	21	$	30
Plus: Current period provision for expected credit losses	71		22		21		2		26		16		4		6
Less: Write-offs, net of recoveries(a)	72		19		28		7		18		9		4		5
Balance at September 30, 2026	$	507	$	105	$	135	$	131	$	136	$	84	$	21	$	31

	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	82		37		22		8		15		11		3		1
Less: Write-offs, net of recoveries	96		44		31		6		15		8		4		3
Balance at September 30, 2025	$	451	$	115	$	145	$	68	$	123	$	72	$	20	$	31

_________

(a)Recoveries were not material to the Registrants.

(b)For ComEd, the decrease in current period provision for expected credit losses when comparing to three months ended September 30, 2025, is primarily the result of decreased aging of receivables.

(c)For ComEd, the decrease in write-offs, net of recoveries when comparing to three months ended September 30, 2025, is primarily the result of decreased disconnection activities.

(d)For BGE, the decrease in current period provision for expected credit losses when comparing to three months ended September 30, 2025, is primarily the result of increased collection activities.

(e)For Pepco and ACE, the increase in current period provision for expected credit losses when comparing to three months ended September 30, 2025, is primarily the result of increased receivable balances.

(f)For ACE, the increase in write-offs, net of recoveries when comparing to three months ended September 30, 2025, is primarily the result of unfavorable customer behavior.


	Nine Months Ended September 30, 2026
	Exelon		ComEd(b)		PECO(c)(d)(e)		BGE(f)(g)		PHI		Pepco(f)(h)		DPL(i)		ACE(f)(h)
Balance at December 31, 2025	$	435	$	115	$	137	$	68	$	115	$	69	$	19	$	27
Plus: Current period provision for expected credit losses	265		49		59		90		67		41		11		15
Less: Write-offs, net of recoveries(a)	193		59		61		27		46		26		9		11
Balance at September 30, 2026	$	507	$	105	$	135	$	131	$	136	$	84	$	21	$	31

	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	224		66		68		34		56		35		13		8
Less: Write-offs, net of recoveries	179		60		56		22		41		22		10		9
Balance at September 30, 2025	$	451	$	115	$	145	$	68	$	123	$	72	$	20	$	31

_________

(a)Recoveries were not material to ComEd, BGE, Pepco, DPL, or ACE.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 5 — Accounts Receivable

(b)For ComEd, the decrease in current period provision for expected credit losses when comparing to nine months ended September 30, 2025, is primarily the result of decreased aging of receivables.

(c)For PECO, the decrease in current period provision for expected credit losses when comparing to nine months ended September 30, 2025, is primarily the result of decreased receivable balances.

(d)For PECO, the increase in write-offs, net of recoveries when comparing to nine months ended September 30, 2025, is primarily the result of increased disconnection activities.

(e)For PECO, the increase in recoveries collected when comparing to nine months ended September 30, 2025, is primarily the result of increased customer repayments.

(f)For BGE, Pepco, and ACE, the increase in current period provision for expected credit losses when comparing to nine months ended September 30, 2025, is primarily the result of increased receivable balances.

(g)For BGE, the increase in write-offs, net of recoveries when comparing to nine months ended September 30, 2025, is primarily the result of increased receivable balances associated with increased customer billings.

(h)For Pepco and ACE the increase in write-offs, net of recoveries when comparing to nine months ended September 30, 2025, is primarily the result of unfavorable customer behavior.

(i)For DPL, the decrease in current period provision for expected credit losses when comparing to nine months ended September 30, 2025, is primarily the result of favorable customer behavior.

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



	Three Months Ended September 30, 2026
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE(b)
Balance at June 30, 2026	$	94	$	25	$	18	$	3	$	48	$	25	$	11	$	12
Plus: Current period provision for expected credit losses	15		6		3		1		5		1		1		3
Less: Write-offs, net of recoveries(a)	13		5		5		1		2		—		1		1
Balance at September 30, 2026	$	96	$	26	$	16	$	3	$	51	$	26	$	11	$	14

	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	7		5		2		1		(1)		—		—		(1)
Less: Write-offs, net of recoveries	16		11		4		1		—		—		—		—
Balance at September 30, 2025	$	98	$	25	$	17	$	5	$	51	$	28	$	9	$	14

_________

(a)Recoveries were not material to the Registrants.

(b)For ACE, the increase in current period provision for expected credit losses when comparing to three months ended September 30, 2025, is primarily the result of increased receivable balances.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 5 — Accounts Receivable


	Nine Months Ended September 30, 2026
	Exelon		ComEd(b)		PECO		BGE		PHI		Pepco		DPL(b)(c)		ACE(b)
Balance at December 31, 2025	$	94	$	23	$	18	$	4	$	49	$	26	$	10	$	13
Plus: Current period provision for expected credit losses	32		14		6		3		9		1		3		5
Less: Write-offs, net of recoveries(a)	30		11		8		4		7		1		2		4
Balance at September 30, 2026	$	96	$	26	$	16	$	3	$	51	$	26	$	11	$	14

	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	15		4		9		(1)		3		1		—		2
Less: Write-offs, net of recoveries	24		13		10		—		1		—		—		1
Balance at September 30, 2025	$	98	$	25	$	17	$	5	$	51	$	28	$	9	$	14

_________

(a)Recoveries were not material to the Registrants.

(b)For ComEd, DPL, and ACE, the increase in current period provision for expected credit losses when comparing to nine months ended September 30, 2025, is primarily the result of increased receivable balances.

(c)For DPL, the increase in write-offs, net of recoveries when comparing to nine months ended September 30, 2025, is primarily the result of unfavorable customer behavior.

Unbilled Customer Revenue

The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of September 30, 2026 and December 31, 2025.


	Unbilled customer revenues(a)
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2026	$	887	$	313	$	160	$	180	$	234	$	122	$	59	$	53
December 31, 2025	1,231		301		278		325		327		155		100		72

__________

(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, 2026 and 2025, 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, 2026	$	3,708	$	967	$	1,091	$	492	$	1,158	$	745	$	209	$	204
Nine months ended September 30, 2025	3,320		814		954		550		1,002		624		201		177

6. Property, Plant, and Equipment (Exelon and BGE)

Project Impairments

In the third quarter of 2026, BGE canceled two capital projects and wrote off $37 million of related costs previously recorded in Property, plant and equipment to Operating and maintenance expense in Exelon's and BGE's Consolidated Statement of Operations and Comprehensive Income.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 7 — Income Taxes

7. Income Taxes (All Registrants)

Rate Reconciliation

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


	Three Months Ended September 30, 2026(a)(b)
	Exelon				ComEd				PECO(c)				BGE
U.S. Federal statutory rate	$	186	21.0	%	$	115	21.0	%	$	36	21.0	%	$	24	21.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	48		5.4		40		7.3		(2)		(1.2)		7		6.2
Tax credits	(1)		(0.1)		1		0.2		—		—		(1)		(0.9)
Change in Unrecognized Tax Benefits	2		0.2		—		—		—		—		—		—
Nontaxable or nondeductible items	(10)		(1.1)		1		0.2		—		—		—		—
Other Adjustments
Plant Basis differences	(36)		(4.0)		(6)		(1.1)		(24)		(13.9)		(2)		(1.8)
Excess deferred tax	(35)		(4.0)		(10)		(1.8)		(2)		(1.3)		(5)		(4.1)
Amortization of ITC, net deferred taxes	—		—		(1)		(0.2)		—		—		—		—
Effective Tax Rate	$	154	17.4	%	$	140	25.6	%	$	8	4.6	%	$	23	20.4	%


	Three Months Ended September 30, 2026(a)(b)
	PHI				PEPCO(d)				DPL				ACE
U.S. Federal statutory rate	$	49	21.0	%	$	7	21.0	%	$	17	21.0	%	$	25	21.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	17		7.3		2		5.6		4		5.0		8		6.6
Tax credits	(1)		(0.4)		(1)		(2.8)		—		—		—		—
Change in Unrecognized Tax Benefits	—		—		—		—		—		—		—		—
Nontaxable or nondeductible items	—		—		—		—		—		—		—		—
Other Adjustments
Plant Basis differences	(3)		(1.3)		(2)		(5.6)		—		—		—		—
Excess deferred tax	(16)		(6.9)		(10)		(29.3)		(2)		(2.2)		(1)		(1.4)
Amortization of ITC, net deferred taxes	—		—		—		—		—		—		—		—
Effective Tax Rate	$	46	19.7	%	$	(4)	(11.1)	%	$	19	23.8	%	$	32	26.2	%


	Three Months Ended September 30, 2025(a)(b)
	Exelon				ComEd(e)				PECO(c)				BGE
U.S. Federal statutory rate	$	217	21.0	%	$	96	21.0	%	$	54	21.0	%	$	22	21.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	58		5.6		34		7.5		(3)		(1.2)		7		6.7
Tax credits	(4)		(0.4)		(1)		(0.2)		—		—		—		—
Nontaxable or nondeductible items	4		0.4		1		0.2		—		—		—		—
Other Adjustments
Plant Basis differences	(52)		(5.0)		(4)		(0.9)		(41)		(15.8)		(1)		(1.0)
Excess deferred tax	(68)		(6.6)		(42)		(9.2)		(5)		(2.0)		(5)		(4.8)
Amortization of ITC, net deferred taxes	—		—		(1)		(0.2)		—		—		—		—
Effective Tax Rate	$	155	15.0	%	$	83	18.2	%	$	5	2.0	%	$	23	21.9	%

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 7 — Income Taxes


	Three Months Ended September 30, 2025(a)(b)
	PHI				PEPCO				DPL				ACE
U.S. Federal statutory rate	$	78	21.0	%	$	41	21.0	%	$	15	21.0	%	$	23	21.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	25		6.6		13		6.6		5		6.9		8		7.2
Tax credits	(1)		(0.3)		—		—		(1)		(1.4)		(1)		(0.9)
Nontaxable or nondeductible items	—		—		(1)		(0.5)		—		—		—		—
Other Adjustments
Plant Basis differences	(2)		(0.5)		(2)		(1.0)		—		—		—		—
Excess deferred tax	(15)		(4.2)		(10)		(5.3)		(2)		(2.9)		(1)		(1.2)
Amortization of ITC, net deferred taxes	—		—		—		—		—		—		—		—
Effective Tax Rate	$	85	22.6	%	$	41	20.8	%	$	17	23.6	%	$	29	26.1	%

__________

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

(b)The Registrants had no adjustments to the following disclosure categories: Foreign Tax Effects, Effects of Changes in Tax Law or Rates Enacted in the Current Period, Effects of Cross-Border Tax Laws, and Changes in Valuation Allowances.

(c)For PECO, the lower effective tax rate is primarily related to state income taxes, net of federal income tax benefit and plant basis differences attributable to tax repair deductions.

(d)For Pepco, the lower effective tax rate is primarily attributable to lower pre-tax earnings due to the unfavorable impacts of the Pepco Electric Base Rate Case’s disallowance of capitalized costs.

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


	Nine Months Ended September 30, 2026(a)(b)
	Exelon				ComEd				PECO(c)				BGE
U.S. Federal statutory rate	$	525	21.0	%	$	271	21.0	%	$	124	21.0	%	$	118	21.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	142		5.7		95		7.4		(6)		(1.0)		34		6.0
Tax credits	(6)		(0.2)		(2)		(0.2)		—		—		(2)		(0.4)
Change in Unrecognized Tax Benefits	(15)		(0.6)		(2)		(0.2)		—		—		(1)		(0.2)
Nontaxable or nondeductible items	6		0.2		2		0.3		1		0.2		1		0.3
Other Adjustments
Plant Basis differences	(110)		(4.4)		(15)		(1.2)		(79)		(13.3)		(10)		(1.8)
Excess deferred tax	(87)		(3.5)		(24)		(1.9)		(9)		(1.7)		(21)		(3.7)
Amortization of ITC, net deferred taxes	(1)		—		(1)		(0.1)		—		—		—		—
Effective Tax Rate	$	454	18.2	%	$	324	25.1	%	$	31	5.2	%	$	119	21.2	%

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 7 — Income Taxes


	Nine Months Ended September 30, 2026(a)(b)
	PHI				PEPCO(d)				DPL				ACE
U.S. Federal statutory rate	$	124	21.0	%	$	42	21.0	%	$	45	21.0	%	$	39	21.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	40		6.8		12		5.9		13		6.1		13		7.0
Tax credits	(2)		(0.3)		(1)		(0.5)		—		—		—		—
Change in Unrecognized Tax Benefits	—		—		—		—		—		—		—		—
Nontaxable or nondeductible items	1		0.2		—		—		—		—		—		—
Other Adjustments
Plant Basis differences	(6)		(1.0)		(4)		(2.0)		(1)		(0.5)		—		—
Excess deferred tax	(32)		(5.5)		(20)		(10.0)		(8)		(3.6)		(4)		(2.3)
Amortization of ITC, net deferred taxes	—		—		—		—		—		—		—		—
Effective Tax Rate	$	125	21.2	%	$	29	14.4	%	$	49	23.0	%	$	48	25.7	%


	Nine Months Ended September 30, 2025(a)(b)
	Exelon				ComEd(e)				PECO(c)				BGE
U.S. Federal statutory rate	$	540	21.0	%	$	232	21.0	%	$	142	21.0	%	$	106	21.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	143		5.6		83		7.5		(15)		(2.2)		32		6.3
Tax credits	(11)		(0.5)		(5)		(0.5)		—		—		(2)		(0.4)
Nontaxable or nondeductible items	9		0.4		1		0.1		1		0.1		—		—
Other Adjustments
Plant Basis differences	(118)		(4.6)		(10)		(0.9)		(94)		(13.9)		(7)		(1.4)
Excess deferred tax	(166)		(6.5)		(99)		(8.9)		(11)		(1.6)		(21)		(4.2)
Amortization of ITC, net deferred taxes	(1)		—		(1)		(0.1)		—		—		—		—
Effective Tax Rate	$	396	15.4	%	$	201	18.2	%	$	23	3.4	%	$	108	21.3	%


	Nine Months Ended September 30, 2025(a)(b)
	PHI				PEPCO				DPL				ACE
U.S. Federal statutory rate	$	170	21.0	%	$	89	21.0	%	$	45	21.0	%	$	39	21.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	54		6.7		27		6.3		14		6.6		13		7.0
Tax credits	(3)		(0.4)		(1)		(0.2)		(1)		(0.5)		(1)		(0.5)
Nontaxable or nondeductible items	1		0.1		—		—		—		—		—		—
Other Adjustments
Plant Basis differences	(5)		(0.6)		(4)		(0.9)		(1)		(0.5)		—		—
Excess deferred tax	(33)		(4.1)		(22)		(5.3)		(8)		(3.5)		(3)		(1.7)
Amortization of ITC, net deferred taxes	—		—		—		—		—		—		—		—
Effective Tax Rate	$	184	22.7	%	$	89	20.9	%	$	49	23.1	%	$	48	25.8	%

__________

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

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

(e)For ComEd, the lower effective tax rate is primarily due to CEJA 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 7 — Income Taxes

State and local Income Tax (Major Jurisdictions)

The state and local jurisdictions that comprise the majority of the effect of the state and local income tax, net of federal income taxes category by Registrant are presented below:


	2026	2025
Exelon	IL, MD	IL, MD
ComEd	IL	IL
PECO	PA	PA
BGE	MD	MD
PHI	MD, NJ	MD, NJ
Pepco	MD	MD
DPL	DE	DE
ACE	NJ	NJ

Unrecognized Tax Benefits

Exelon, PHI and DPL have the following unrecognized tax benefits at September 30, 2026 and December 31, 2025. ComEd's, PECO's, BGE's, Pepco's, and ACE's amounts are not material.


	Exelon(a)		PHI		DPL
September 30, 2026	$	88	$	54	$	18
December 31, 2025	100		48		11

__________

(a)At September 30, 2026 and December 31, 2025, Exelon's unrecognized tax benefits are inclusive of $20 million and $31 million, respectively, related to Constellation's share of unrecognized tax benefits for periods prior to the separation. Exelon reflected an offsetting receivable of $20 million and $31 million in Other deferred debits and other assets in the Consolidated Balance Sheet for these amounts.

Other Tax Matters

Tax Matters Agreement (Exelon)

In February 2022, in connection with the separation between Exelon and Constellation, the parties entered into a TMA. 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, 2026, 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, 2026, there is no balance due to or from Constellation.

Tax Attributes. At the date of separation certain tax attributes, primarily pre-separation tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA provides that Exelon will reimburse Constellation when those allocated tax attribute carryforwards are utilized. In Q1 2026, Exelon received $235 million of payments from Constellation as reimbursement for a reduction in previously utilized pre-separation tax credit carryforwards due to the filing of amended federal tax returns. In Q2 2026, Exelon remitted $53 million of payments to Constellation for the utilization of pre-separation tax credit

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 7 — Income Taxes

carryforwards. At September 30, 2026, Exelon recorded a payable of $106 million and $271 million in Other current liabilities and Other deferred credits and other liabilities, respectively, in the Consolidated Balance Sheet for tax attribute carryforwards that are expected to be utilized and reimbursed to Constellation.

Corporate Alternative Minimum Tax (All Registrants)

On August 16, 2022, the IRA was signed into law and implements a new corporate alternative minimum tax (CAMT) that imposes a 15.0% tax on modified GAAP net income. Corporations will now pay the greater of 15.0% of financial statement pre-tax income (with certain adjustments) or their regular federal tax liability, which is federal taxable income multiplied by 21.0% federal corporate tax rate. 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.

For the years ended December 31, 2025, December 31, 2024, and December 31, 2023, based on the existing guidance in effect at that time, Exelon and each of the Utility Registrants were subject to and reported the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets.

On February 18, 2026, the U.S. Treasury issued guidance addressing the implementation of CAMT in the form of a notice. The new guidance permits corporate taxpayers to deduct repair and maintenance costs in the calculation of their CAMT liabilities. The notice applies retroactively, permitting Exelon to file amended returns for both 2024 and 2023 to reduce its CAMT liability by $80 million. Pursuant to the TMA, Exelon received reimbursement from Constellation for $235 million due to the reduction in the amount of Constellation's tax credits needed to offset Exelon's CAMT liability on its amended returns.

The impact of the notice was recorded as of March 31, 2026.

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.

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.

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, 2026, and 2025.


	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2026	$	125	$	27	$	(3)	$	21	$	8	$	9	$	3
September 30, 2025	20		14		12		23		12		7		4

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 8 — Retirement Benefits

8. Retirement Benefits (All Registrants)

Defined Benefit Pension and OPEB

The majority of the 2026 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 5.42%. The majority of the 2026 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 5.34%.

During the first quarter of 2026, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2026. This valuation resulted in an increase to the pension obligation of $6 million and an increase to the OPEB obligation of $10 million and a decrease to the asset of $2 million, respectively. Additionally, AOCI decreased by $4 million (after-tax) and regulatory assets increased by $23 million and liabilities increased by $1 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, 2026 and 2025.


	Pension Benefits				OPEB
	Three Months Ended September 30,				Three Months Ended September 30,
	2026		2025		2026		2025
Components of net periodic benefit cost
Service cost	$	40	$	38	$	6	$	7
Interest cost	143		146		25		26
Expected return on assets	(176)		(179)		(21)		(21)
Amortization of:
Prior service cost (credit)	1		1		(2)		(2)
Actuarial loss (gain)	51		53		—		(1)


Net periodic benefit cost	$	59	$	59	$	8	$	9

	Pension Benefits				OPEB
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2026		2025		2026		2025
Components of net periodic benefit cost
Service cost	$	120	$	115	$	20	$	19
Interest cost	428		439		75		76
Expected return on assets	(528)		(535)		(64)		(63)
Amortization of:
Prior service cost (credit)	2		2		(6)		(6)
Actuarial loss (gain)	151		159		(1)		(2)


Net periodic benefit cost	$	173	$	180	$	24	$	24

The amounts below represent the Registrants' allocated pension and OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For 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 8 — Retirement Benefits


	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and OPEB Costs	2026		2025		2026		2025
Exelon	$	67	$	68	$	196	$	204
ComEd	26		22		80		64
PECO	5		2		13		5
BGE	7		16		21		46
PHI	21		23		62		72
Pepco	9		8		23		26
DPL	4		4		11		12
ACE	2		3		7		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, 2026 and 2025.


	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plan Employer Contributions	2026		2025		2026		2025
Exelon	$	33	$	30	$	97	$	86
ComEd	17		12		41		34
PECO	5		4		14		12
BGE	3		3		9		9
PHI	3		5		15		15
Pepco	1		1		4		4
DPL	1		1		3		3
ACE	—		1		2		2

9. Derivative Financial Instruments (All Registrants)

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

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

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

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 9 — 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 2 — Regulatory Matters of the 2025 Form 10-K for additional information.

(b)The fair value of the DPL economic hedge is not material at September 30, 2026 and December 31, 2025.

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, 2026 would result in an immaterial impact to Exelon's Consolidated Net income.

Below is a summary of the interest rate hedge balances at September 30, 2026 and December 31, 2025.


	Derivatives Designated as Hedging Instruments
	September 30, 2026		December 31, 2025
Other current assets	$	—	$	3
Other deferred debits (noncurrent assets)	17		—
Total derivative assets	17		3
Mark-to-market derivative liabilities (current liabilities)	—		(4)
Mark-to-market derivative liabilities (noncurrent liabilities)	—		—
Total mark-to-market derivative liabilities	—		(4)
Total mark-to-market derivative net assets (liabilities)	$	17	$	(1)

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 9 — Derivative Financial Instruments

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. The gains and losses reclassified out of AOCI for the three and nine months ended September 30, 2026 and 2025 are immaterial.

In February 2026, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $550 million upon issuance of $775 million of debt. See Note 10 – Debt and Credit Agreements for additional information on the debt issuance. The settlements resulted in a net cash payment of $6 million. The accumulated AOCI loss of $4 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 2026, Exelon Corporate entered into $90 million notional of 10-year maturity floating-to-fixed swaps designated as cash flow hedges. The following table provides the notional amounts outstanding held by Exelon at September 30, 2026 and December 31, 2025.


	September 30, 2026		December 31, 2025
5-year maturity floating-to-fixed swaps	$	60	$	335
10-year maturity floating-to-fixed swaps	240		365
Total	$	300	$	700

The related AOCI derivative gain for the three and nine months ended September 30, 2026 was $11 million and $13 million (net of tax), respectively. 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. See Note 14 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.

Credit Risk (All Registrants)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. 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, 2026. 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, at September 30, 2026 and December 31, 2025:


	September 30, 2026		December 31, 2025
Exelon	$	312	$	223
ComEd	231		192
PECO	18		6
BGE	4		4
PHI	59		21
Pepco	21		13
DPL	2		3
ACE	36		5

The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO's, BGE's, and DPL's credit rating. As of September 30, 2026, 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, 2026, they could have been required to post collateral to their counterparties of $26 million, $14 million, and $10 million, respectively.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 10 — Debt and Credit Agreements

10. Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

Exelon Corporate, ComEd, and BGE meet their short-term liquidity needs primarily through commercial paper issuances. PECO also utilizes commercial paper, supplemented by borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE similarly rely on commercial paper, along with borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity needs through 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, 2026 and December 31, 2025.


	Outstanding Commercial Paper at				Average Interest Rate on Commercial Paper Borrowings at
Commercial Paper Issuer	September 30, 2026		December 31, 2025		September 30, 2026		December 31, 2025
Exelon(a)	$	434	$	612	4.19	%	3.94	%
ComEd	$	—	$	—	—	%	—	%
PECO	$	—	$	—	—	%	—	%
BGE	$	—	$	—	—	%	—	%
PHI(b)	$	—	$	612	—	%	3.94	%

Pepco	$	—	$	303	—	%	3.93	%
DPL	$	—	$	161	—	%	3.94	%
ACE	$	—	$	148	—	%	3.94	%

__________

(a)Exelon Corporate had $434 million outstanding commercial paper borrowings at September 30, 2026 and no outstanding commercial paper borrowings at December 31, 2025.

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

Revolving Credit Agreements

On August 29, 2024, Exelon Corporate and each of the Utility Registrants amended and restated their respective syndicated revolving credit facilities, 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 1.000%
BGE	$	600	SOFR plus 1.000%
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, 2026.

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.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 10 — Debt and Credit Agreements

See Note 14 — Debt and Credit Agreements of the 2025 Form 10-K for additional information on the Registrants' credit facilities.

Short-Term Loan Agreements

On March 25, 2026, Exelon Corporate entered into two term loan agreements for $350 million and $150 million. Both agreements mature on March 24, 2027. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.85% and all indebtedness thereunder is unsecured. The loans are reflected in Exelon's Consolidated Balance Sheet within Short-term borrowings.

Long-Term Debt

Issuance of Long-Term Debt

During the nine months ended September 30, 2026, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Senior Notes

4.95%

March 15, 2036

$775

Repay existing indebtedness and for general corporate purposes.

ComEd

First Mortgage Bonds

4.55%

June 1, 2031

600

Repay existing indebtedness and for general corporate purposes.

ComEd

First Mortgage Bonds

5.85%

June 1, 2056

825

Repay existing indebtedness and for general corporate purposes.

PECO

First Mortgage Bonds

5.00%

September 1, 2031

750

Repay existing indebtedness and for general corporate purposes.

BGE

Notes

5.15%

June 1, 2033

500

Repay existing indebtedness and for general corporate purposes.

BGE

Notes

6.05%

June 1, 2056

425

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.00%

March 19, 2036

110

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.30%

March 19, 2041

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.74%

June 17, 2056

130

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

5.74%

March 19, 2056

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

5.00%

September 16, 2036

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

4.95%

March 19, 2036

100

Repay existing indebtedness and for general corporate purposes.

Convertible Senior Notes

On December 4, 2025, Exelon Corporation issued $1 billion aggregate principal amount of 3.25% Convertible Senior Notes due 2029 (Convertible Senior Notes). The Convertible Senior Notes are reflected as Long-term debt on Exelon’s Consolidated Balance Sheet.

The Convertible Senior Notes are senior, unsecured notes that bear interest at a fixed rate of 3.25% per year, payable semiannually in arrears on March 15 and September 15 of each year, beginning on September 15, 2026. The Convertible Senior Notes will mature on March 15, 2029, unless earlier converted or repurchased in accordance with their terms.

Under the following circumstances, holders may convert the Convertible Senior Notes at their option prior to the close of business on the business day preceding December 15, 2028:

•during any calendar quarter beginning after the quarter ending on March 31, 2026, if the last reported sale price of Exelon’s common stock for at least 20 trading days (whether consecutive or not) during the period of 30 consecutive trading days ending on, and including, the last trading day of the immediately

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 10 — Debt and Credit Agreements

preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day as determined by Exelon;

•during the five business day period after any ten consecutive trading day period (measurement period) in which the applicable trading price per $1,000 principal amount of notes for each trading day of the measurement period was less than 98% of the product of the last reported sale price of the common stock and the conversion rate on each such trading day;

•upon the occurrence of certain corporate events specified in the respective supplemental indentures governing the Convertible Senior Notes.

On or after December 15, 2028, a holder may convert for all, or any portion of its Convertible Senior Notes at any time prior to the close of business on the business day immediately preceding the applicable maturity date regardless of the foregoing conditions.

Exelon will settle conversions of the Convertible Senior Notes by paying cash up to the aggregate principal amount to be converted and paying or delivering, as the case may be, cash, shares of common stock, or a combination of cash and shares of common stock, at Exelon’s discretion, in respect of the remainder, if any, of Exelon's conversion obligation in excess of the aggregate principal amount of the Convertible Senior Notes being converted. The Convertible Senior Notes are initially convertible at 18 shares per $1,000 principal amount, which is equivalent to an initial conversion price of approximately 57 per share of common stock. The initial conversion price of the Convertible Senior Notes represents a premium of approximately 25% over the last reported sale price of Exelon’s common stock on the Nasdaq Global Select Market on December 1, 2025. These conversions will be subject to adjustment upon the occurrence of certain specified events but will not be adjusted for accrued and unpaid interest. In addition, upon the occurrence of a make-whole fundamental change (as defined in the indenture) Exelon will, in certain circumstances, increase the applicable conversion rate by a number of additional shares of common stock for conversions in connection with the make-whole fundamental change.

As of September 30, 2026, no shares of the Convertible Senior Notes have been converted.

EPS Impact

Diluted earnings per common shares will also reflect the dilutive effect of potential common shares from share-based awards and convertible notes. The dilutive effect of the Convertible Senior Notes is computed using the if-converted method. For the three and nine months ended September 30, 2026, no incremental shares were assumed converted or included in the diluted earnings per common share resulting from the Convertible Senior Notes.

Tax-Exempt Bonds

As of September 30, 2026, DPL had $78.4 million outstanding of its 3.60% Delaware Economic Development Authority's Gas Facilities Refunding Revenue Bonds, maturing on January 1, 2031. The bonds were previously reoffered in July 2025. There have been no material changes to the terms since December 31, 2025. See Note 14 — Debt and Credit Agreements of the 2025 Form 10-K for additional information on the DPL reoffering of tax-exempt bonds.

Debt Covenants

As of September 30, 2026, the Registrants are in compliance with debt covenants.

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

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

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

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

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

•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 15 — Fair Value of Financial Assets and Liabilities of the 2025 Form 10-K.

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, 2026 and December 31, 2025. 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, 2026										December 31, 2025
	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 (b)	$	51,869	$	—	$	39,524	$	4,468	$	43,992	$	49,078	$	—	$	40,637	$	4,318	$	44,955
ComEd	13,667		—		11,186		—		11,186		12,753		—		11,291		—		11,291
PECO	7,143		—		5,798		—		5,798		6,396		—		5,593		—		5,593
BGE	6,610		—		5,568		—		5,568		6,041		—		5,510		—		5,510
PHI	10,134		—		3,904		4,468		8,372		9,590		—		4,236		4,318		8,554
Pepco	4,940		—		2,312		1,986		4,298		4,632		—		2,546		1,861		4,407
DPL	2,498		—		607		1,427		2,034		2,344		—		657		1,410		2,067
ACE	2,136		—		785		1,055		1,840		2,033		—		819		1,047		1,866
Long-Term Debt to Financing Trusts
Exelon	$	390	$	—	$	—	$	388	$	388	$	390	$	—	$	—	$	403	$	403
ComEd	206		—		—		206		206		206		—		—		216		216
PECO	184		—		—		182		182		184		—		—		187		187

__________

(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 14 — Debt and Credit Agreements of the 2025 Form 10-K for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 9 — Leases of the 2025 Form 10-K for finance lease liabilities.

(b)Includes the net carrying amount and the estimated fair value (Level 2) of the Convertible Senior Notes $1 billion and $964 million for the quarter ended September 30, 2026, respectively.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

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, 2026 and December 31, 2025. Exelon and the Utility Registrants have immaterial and no financial assets or liabilities measured using the NAV practical expedient, respectively:

Exelon


	At September 30, 2026						At December 31, 2025
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	1,718	$	—	$	—	$	1,718	$	825	$	—	$	—	$	825
Rabbi trust investments
Cash equivalents	110		—		—		110		101		—		—		101
Mutual funds	78		—		—		78		71		—		—		71
Fixed income	—		6		—		6		—		6		—		6
Life insurance contracts	—		80		19		99		—		79		21		100
Rabbi trust investments subtotal	188		86		19		293		172		85		21		278

Interest rate derivative assets
Derivatives designated as hedging instruments	—		17		—		17		—		3		—		3

Interest rate derivative assets subtotal	—		17		—		17		—		3		—		3
Total assets	1,906		103		19		2,028		997		88		21		1,106
Liabilities
Commodity derivative liabilities	—		—		(117)		(117)		—		—		(131)		(131)
Interest rate derivative liabilities
Derivatives designated as hedging instruments	—		—		—		—		—		(4)		—		(4)

Interest rate derivative liabilities subtotal	—		—		—		—		—		(4)		—		(4)
Deferred compensation obligation	—		(67)		—		(67)		—		(71)		—		(71)
Total liabilities	—		(67)		(117)		(184)		—		(75)		(131)		(206)
Total net assets (liabilities)	$	1,906	$	36	$	(98)	$	1,844	$	997	$	13	$	(110)	$	900

__________

(a)Exelon excludes cash of $166 million and $180 million at September 30, 2026 and December 31, 2025, respectively, and restricted cash of $236 million and $196 million at September 30, 2026 and December 31, 2025, respectively, and includes long-term restricted cash of $49 million and $50 million at September 30, 2026 and December 31, 2025, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

ComEd, PECO, and BGE


	ComEd								PECO								BGE
At September 30, 2026	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)	$	573	$	—	$	—	$	573	$	81	$	—	$	—	$	81	$	834	$	—	$	—	$	834
Rabbi trust investments
Cash equivalents	—		—		—		—		3		—		—		3		—		—		—		—
Mutual funds	—		—		—		—		14		—		—		14		16		—		—		16
Life insurance contracts	—		—		—		—		—		24		—		24		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		17		24		—		41		16		—		—		16

Total assets	573		—		—		573		98		24		—		122		850		—		—		850
Liabilities
Commodity derivative liabilities(b)	—		—		(117)		(117)		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		(10)		—		(10)		—		(7)		—		(7)		—		(4)		—		(4)
Total liabilities	—		(10)		(117)		(127)		—		(7)		—		(7)		—		(4)		—		(4)
Total net assets (liabilities)	$	573	$	(10)	$	(117)	$	446	$	98	$	17	$	—	$	115	$	850	$	(4)	$	—	$	846


	ComEd								PECO								BGE
At December 31, 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)	$	393	$	—	$	—	$	393	$	93	$	—	$	—	$	93	$	205	$	—	$	—	$	205
Rabbi trust investments
Mutual funds	—		—		—		—		13		—		—		13		10		—		—		10
Life insurance contracts	—		—		—		—		—		25		—		25		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		13		25		—		38		10		—		—		10
Total assets	393		—		—		393		106		25		—		131		215		—		—		215
Liabilities
Commodity derivative liabilities(b)	—		—		(131)		(131)		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		(9)		—		(9)		—		(8)		—		(8)		—		(4)		—		(4)
Total liabilities	—		(9)		(131)		(140)		—		(8)		—		(8)		—		(4)		—		(4)
Total net assets (liabilities)	$	393	$	(9)	$	(131)	$	253	$	106	$	17	$	—	$	123	$	215	$	(4)	$	—	$	211

__________

(a)ComEd excludes cash of $75 million and $77 million at September 30, 2026 and December 31, 2025, respectively, and restricted cash of $231 million and $193 million at September 30, 2026 and December 31, 2025, respectively. Additionally,

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

ComEd includes long-term restricted cash of $49 million and $50 million at September 30, 2026 and December 31, 2025, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO excludes cash of $26 million and $23 million at September 30, 2026 and December 31, 2025, respectively. BGE excludes cash of $11 million and $15 million at September 30, 2026 and December 31, 2025, respectively.

(b)The Level 3 balance consists of the current and noncurrent liability of $21 million and $96 million, respectively, at September 30, 2026 and $25 million and $106 million, respectively, at December 31, 2025 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL, and ACE


	At September 30, 2026								At December 31, 2025
PHI	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	205	$	—	$	—	$	205	$	83	$	—	$	—	$	83
Rabbi trust investments
Cash equivalents	103		—		—		103		99		—		—		99
Mutual funds	8		—		—		8		9		—		—		9
Fixed income	—		6		—		6		—		6		—		6
Life insurance contracts	—		23		20		43		—		23		20		43
Rabbi trust investments subtotal	111		29		20		160		108		29		20		157
Total assets	316		29		20		365		191		29		20		240
Liabilities
Deferred compensation obligation	—		(8)		—		(8)		—		(9)		—		(9)



Total liabilities	—		(8)		—		(8)		—		(9)		—		(9)
Total net assets	$	316	$	21	$	20	$	357	$	191	$	20	$	20	$	231


	Pepco								DPL								ACE
At September 30, 2026	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)	$	102	$	—	$	—	$	102	$	74	$	—	$	—	$	74	$	—	$	—	$	—	$	—




Rabbi trust investments
Cash equivalents	103		—		—		103		—		—		—		—		—		—		—		—

Life insurance contracts	—		23		19		42		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	103		23		19		145		—		—		—		—		—		—		—		—
Total assets	205		23		19		247		74		—		—		74		—		—		—		—
Liabilities
Deferred compensation obligation	—		(1)		—		(1)		—		—		—		—		—		—		—		—



Total liabilities	—		(1)		—		(1)		—		—		—		—		—		—		—		—
Total net assets	$	205	$	22	$	19	$	246	$	74	$	—	$	—	$	74	$	—	$	—	$	—	$	—

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities


	Pepco								DPL								ACE
At December 31, 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)	$	33	$	—	$	—	$	33	$	3	$	—	$	—	$	3	$	—	$	—	$	—	$	—
Rabbi trust investments
Cash equivalents	98		—		—		98		—		—		—		—		—		—		—		—


Life insurance contracts	—		23		20		43		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	98		23		20		141		—		—		—		—		—		—		—		—
Total assets	131		23		20		174		3		—		—		3		—		—		—		—
Liabilities
Deferred compensation obligation	—		(1)		—		(1)		—		—		—		—		—		—		—		—



Total liabilities	—		(1)		—		(1)		—		—		—		—		—		—		—		—
Total net assets	$	131	$	22	$	20	$	173	$	3	$	—	$	—	$	3	$	—	$	—	$	—	$	—

__________

(a)PHI excludes cash of $43 million and $56 million at September 30, 2026 and December 31, 2025, respectively, and restricted cash of $5 million and $2 million at September 30, 2026 and December 31, 2025. Pepco excludes cash of $16 million and $22 million at September 30, 2026 and December 31, 2025, respectively. DPL excludes cash of $7 million and $9 million at September 30, 2026 and December 31, 2025, respectively. ACE excludes cash of $14 million and $22 million at September 30, 2026 and December 31, 2025, respectively and restricted cash of $5 million and $2 million at September 30, 2026 and December 31, 2025, 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, 2026 and 2025:



	Exelon		ComEd		PHI and Pepco
Three Months Ended September 30, 2026	Total		Commodity Derivatives		Life Insurance Contracts
Balance at June 30, 2026	$	(109)	$	(128)	$	19
Total realized / unrealized gains (losses)
Included in net income(a)	—		—		—


Included in regulatory assets/liabilities(b)	11		11		—





Settlements	—		—		—


Balance at September 30, 2026(c)	$	(98)	$	(117)	$	19
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2026	$	—	$	—	$	—

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities



	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(b)	7		7		—





Settlements	(1)		—		(1)


Balance at September 30, 2025(c)	$	(105)	$	(128)	$	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)	$	—	$	—



	Exelon		ComEd		PHI and Pepco
Nine Months Ended September 30, 2026	Total		Commodity Derivatives		Life Insurance Contracts
Balance at December 31, 2025	$	(110)	$	(131)	$	20
Total realized / unrealized gains (losses)
Included in net income(a)	—		—		—


Included in regulatory assets/liabilities(b)	14		14		—





Settlements	(2)		—		(1)


Balance at September 30, 2026(c)	$	(98)	$	(117)	$	19
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2026	$	—	$	—	$	—



	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(b)	4		4		—





Settlements	(1)		—		(1)


Balance at September 30, 2025(c)	$	(105)	$	(128)	$	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

__________

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

(b)For ComEd, this includes $8 million of increases in fair value and an increase for realized gains due to settlements of $3 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2026. 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 $8 million of decreases in fair value and an increase for realized gains due to settlements of $22 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2026. 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.

(c)For ComEd, the balance of the current and noncurrent asset was zero as of September 30, 2026. The balance consists of a current and noncurrent liability of $21 million and $96 million, respectively, as of September 30, 2026.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

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, 2026		Fair Value at December 31, 2025		Valuation Technique	Unobservable Input	2026 Range & Arithmetic Average				2025 Range & Arithmetic Average
Commodity derivatives	$	(117)	$	(131)	Discounted Cash Flow	Forward power price(a)	$26.75	-	$66.55	$43.02	$29.75	-	$61.84	$41.95

________

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

12. Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 16 — Commitments and Contingencies of the 2025 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, 2026:


Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments(a)	20		18		18		—		—

__________

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

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 12 — Commitments and Contingencies

Commercial Commitments (All Registrants). The Registrants’ commercial commitments at September 30, 2026, representing commitments potentially triggered by future events were as follows:


			Expiration within
	Total		2026		2027		2028		2029		2030		2031 and beyond
Exelon
Letters of credit(a)	$	55	$	10	$	45	$	—	$	—	$	—	$	—
Surety bonds(b)	472		72		235		165		—		—		—
Financing trust guarantees(c)	378		—		—		78		—		—		300
Guaranteed lease residual values(d)	25		—		—		6		4		4		11
Total commercial commitments	$	930	$	82	$	280	$	249	$	4	$	4	$	311

ComEd
Letters of credit(a)	$	15	$	4	$	11	$	—	$	—	$	—	$	—
Surety bonds(b)	144		10		134		—		—		—		—
Financing trust guarantees(c)	200		—		—		—		—		—		200
Total commercial commitments	$	359	$	14	$	145	$	—	$	—	$	—	$	200

PECO
Letters of credit(a)	$	4	$	—	$	4	$	—	$	—	$	—	$	—
Surety bonds(b)	19		—		19		—		—		—		—
Financing trust guarantees(c)	178		—		—		78		—		—		100
Total commercial commitments	$	201	$	—	$	23	$	78	$	—	$	—	$	100

BGE
Letters of credit(a)	$	27	$	4	$	23	$	—	$	—	$	—	$	—
Surety bonds(b)	93		1		5		87		—		—		—
Total commercial commitments	$	120	$	5	$	28	$	87	$	—	$	—	$	—

PHI
Letters of credit(a)	$	6	$	—	$	6	$	—	$	—	$	—	$	—
Surety bonds(b)	157		57		22		78		—		—		—
Guaranteed lease residual values(d)	25		—		—		6		4		4		11
Total commercial commitments	$	188	$	57	$	28	$	84	$	4	$	4	$	11

Pepco
Letters of credit(a)	$	3	$	—	$	3	$	—	$	—	$	—	$	—
Surety bonds(b)	143		51		14		78		—		—		—
Guaranteed lease residual values(d)	9		—		—		2		1		2		4
Total commercial commitments	$	155	$	51	$	17	$	80	$	1	$	2	$	4

DPL
Letters of credit(a)	$	1	$	—	$	1	$	—	$	—	$	—	$	—
Surety bonds(b)	8		3		5		—		—		—		—
Guaranteed lease residual values(d)	9		—		—		2		2		1		4
Total commercial commitments	$	18	$	3	$	6	$	2	$	2	$	1	$	4

ACE
Letters of credit(a)	$	2	$	—	$	2	$	—	$	—	$	—	$	—
Surety bonds(b)	6		3		3		—		—		—		—
Guaranteed lease residual values(d)	7		—		—		2		1		1		3
Total commercial commitments	$	15	$	3	$	5	$	2	$	1	$	1	$	3

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 12 — 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.

(c)Reflects guarantee of ComEd and PECO securities held by ComEd Financing III, PECO Trust III, and PECO Trust IV.

(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 $59 million guaranteed by Exelon and PHI, of which $21 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 2034.

•PECO has 5 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 2027.

•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 2026, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The study resulted in increases of $12 million and $2 million to the environmental liability and related Regulatory asset for ComEd and PECO, respectively. The increases were primarily due to increased costs resulting from inflation, adjustments to unit costs, and changes in remediation plans.

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 12 — Commitments and Contingencies

At September 30, 2026 and December 31, 2025, 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, 2026				December 31, 2025
	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	$	369	$	318	$	386	$	321
ComEd	295		295		289		289
PECO	16		13		23		22
BGE	13		10		13		10
PHI	44		—		57		—
Pepco	42		—		55		—
DPL	2		—		1		—
ACE	—		—		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 Constellation 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 and waterside areas closed on April 18, 2025 and October 31, 2025, respectively. 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. 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/Constellation 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

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 12 — Commitments and Contingencies

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, and the second installment of $12 million on April 7, 2026. 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 12 — 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, which the DOEE approved in November 2025. Pepco also submitted an environmental assessment to the DOEE of the vault system pursuant to the Consent Order in July 2024. In response to the DOEE's comments, Pepco made revised submissions in May 2025, September 2025, and January 2026. The DOEE approved Pepco's vault system report on February 2, 2026. 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

100

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 12 — Commitments and Contingencies

(Stipulation), which contained the terms of the settlement. The settlement terms include but are not limited to: a payment of $40 million to Exelon by Exelon’s insurers; a combined $10 million award for service awards and attorneys' fees and expenses; 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. The court granted the renewed motion for preliminary approval on November 17, 2025, and held the final settlement hearing on May 5, 2026. On September 22, 2026, the court granted final approval of the settlement, approved the related service awards and attorneys’ fees and expenses. On October 21, 2026, the non-settling plaintiffs filed their notice of appeal of the final approval order.

Maryland Sales and Use Tax Refund Claim (Exelon, BGE, PHI, Pepco, and DPL). Maryland imposes a 6% sales tax on the purchase of most goods and services. BGE, Pepco, and DPL have filed or plan to file refund claims that treat electric transmission and distribution machinery and equipment as nontaxable pursuant to the manufacturing exemption available under Maryland law. These claims were initially denied by the Maryland Comptroller.

On November 22, 2024, the Appellate Court of Maryland, in a case involving a regulated electric utility operating in Maryland, ruled that the purchase of certain transmission and distribution equipment qualifies 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. 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 decision, which was granted. 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.

On July 17, 2026, the Supreme Court of Maryland issued a decision affirming that purchases of certain transmission and distribution equipment qualify for the sales tax manufacturing exemption. The Supreme Court of Maryland also concluded that sales tax refund claims are eligible for interest.

As of September 30, 2026, Exelon, BGE, PHI, Pepco, and DPL have filed or plan to file refund claims including interest of $165 million, $110 million, $55 million, $35 million, and $20 million, respectively. The receivable will be recorded in the period that resolution is reached with taxing authorities. The sales tax payments were primarily capitalized; therefore, that portion of the refund would be recorded as a reduction to PP&E included in rate base.

Exelon, BGE, PHI, Pepco, and DPL plan to work collaboratively with the MDPSC and other key stakeholders to determine the optimal approach to reduce customer bills for the sales tax refund. Exelon, BGE, PHI, Pepco, and DPL plan to begin sharing those tax benefits with customers following the receipt of the refund from the Maryland Comptroller.

General (All Registrants). The Registrants are involved in various other litigation matters for personal injury, property damage and other claims 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 various insurance programs, including general liability insurance coverage which provides coverage for personal injury or wrongful death cases. Any accrued liability is recorded on a gross basis with a receivable also recorded for any probable insurance recoveries. 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.

101

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 13 — Shareholders' Equity

13. Shareholders' Equity (Exelon)

At-the-Market Program

On May 2, 2025, Exelon executed an equity distribution agreement ("2025 Equity Distribution Agreement"), 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. 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. Exelon issued the following shares of Common stock in the second and third quarters of 2026:


Effective Period	Shares Issued (in millions)	Weighted-Average Net Price		Net Proceeds (a) (in millions)
Q2 2026 (b)	8.7	$	44.03	$	382
Q3 2026 (c)	2.3	$	43.29	$	101

_________

(a)Proceeds were used for general corporate purposes.

(b)In the second quarter of 2026, Exelon settled all forward sale agreements with a November 16, 2026 maturity date and a portion of the forward sale agreements with December 15, 2026 and July 30, 2027 maturity dates that were entered into by various forward sellers under the ATM program as outlined below.

(c)In the third quarter of 2026, Exelon settled a forward sale agreement with a December 15, 2026 maturity date that was entered into by the forward seller under the ATM program as outlined below.

In the first quarter of 2026, Exelon entered into various forward sale agreements under the 2025 ATM program. The forward sale agreements require Exelon to, at its election prior to the maturity date, 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. The following forward sale agreements were entered into under Exelon’s ATM program in the first quarter of 2026:


Effective Period	Shares Available (in millions)	Weighted-Average Net Price		Maturity Date
Q1 2026	5.4	$	47.67	July 30, 2027
Q1 2026	6.4	$	48.68	September 2, 2027

Additionally, the following forward sale agreements were entered into during the twelve months ended 2025 under Exelon’s ATM program and were not settled as of December 31, 2025:


Effective Period	Shares Available (in millions)	Weighted-Average Net Price		Maturity Date
Q2 2025	3.6	$	43.17	November 16, 2026
Q3 2025	11.5	$	43.73	December 15, 2026
Q4 2025	0.8	$	45.42	December 15, 2026

No amounts have been or will be recorded on Exelon's Consolidated 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 three and nine months ended September 30, 2026, approximately 16.5 million and 16.3 million shares, respectively, 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, $1.0 billion of Common stock remained available for sale pursuant to the ATM program as of September 30, 2026.

102

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 14 — Changes in Accumulated Other Comprehensive Income (Loss)

14. 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, 2026	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Total
Balance at June 30, 2026	$	28	$	(778)	$	(750)
OCI before reclassifications	12		—		12
Amounts reclassified from AOCI	(2)		7		5
Net current-period OCI	10		7		17
Balance at September 30, 2026	$	38	$	(771)	$	(733)


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)


Nine Months Ended September 30, 2026	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Total
Balance at December 31, 2025	$	33	$	(795)	$	(762)
OCI before reclassifications	10		3		13
Amounts reclassified from AOCI	(5)		21		16
Net current-period OCI	5		24		29
Balance at September 30, 2026	$	38	$	(771)	$	(733)


Nine Months Ended September 30, 2025	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Total
Balance at 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)

______

(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 12 — Retirement Benefits of the 2025 Form 10-K and Note 8 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

103

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 14 — Changes in Accumulated Other Comprehensive Income (Loss)

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,
	2026		2025		2026		2025
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	—		—		(1)		(2)
Unrealized (losses) gains on cash flow hedges	(3)		2		(3)		4

15. Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

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


	Taxes other than income taxes
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2026
Utility taxes(a)	$	287	$	93	$	62	$	29	$	103	$	94	$	8	$	1
Property	132		20		5		67		39		32		7		—
Payroll	38		12		5		4		8		2		1		1

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

Nine Months Ended September 30, 2026
Utility taxes(a)	$	816	$	264	$	171	$	92	$	288	$	260	$	25	$	3
Property	381		40		15		193		132		92		37		2
Payroll	108		29		14		13		25		5		3		3

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

_________

(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.

104

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 15 — Supplemental Financial Information


	Other, net
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2026
AFUDC — Equity	$	66	$	25	$	12	$	17	$	12	$	9	$	2	$	1
Non-service net periodic benefit cost	(12)		—		—		—		—		—		—		—

Three Months Ended September 30, 2025
AFUDC — Equity	$	49	$	19	$	9	$	11	$	10	$	8	$	1	$	1
Non-service net periodic benefit cost	(13)		—		—		—		—		—		—		—

Nine Months Ended September 30, 2026
AFUDC — Equity	$	186	$	71	$	33	$	47	$	35	$	27	$	5	$	3
Non-service net periodic benefit cost	(33)		—		—		—		—		—		—		—

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

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, 2026
Property, plant, and equipment(a)	$	2,419	$	966	$	371	$	400	$	640	$	284	$	180	`	$	173
Amortization of regulatory assets and liabilities, net(a)	491		292		2		96		101		59		20			22
Amortization of intangible assets, net(a)	—		—		—		—		—		—		—			—


ARO accretion(b)	2		—		—		—		—		—		—			—
Total depreciation, amortization, and accretion	$	2,912	$	1,258	$	373	$	496	$	741	$	343	$	200		$	195

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

__________

(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.

105

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 15 — Supplemental Financial Information


	Other non-cash operating activities
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2026
Pension and OPEB costs	$	196	$	80	$	13	$	21	$	62	$	23	$	11	$	7
Allowance for credit losses	243		62		70		51		60		28		12		20


True-up adjustments to decoupling mechanisms and formula rates(a)	140		62		(10)		35		53		13		8		32





Amortization of operating ROU asset	17		—		—		5		8		2		3		1


AFUDC — Equity	(186)		(71)		(33)		(47)		(35)		(27)		(5)		(3)

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)

__________

(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 2 — Regulatory Matters of the 2025 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.

106

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 15 — Supplemental Financial Information


	Cash, cash equivalents, and restricted cash
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at September 30, 2026
Cash and cash equivalents	$	1,469	$	300	$	107	$	842	$	207	$	79	$	79	$	15
Restricted cash and cash equivalents	602		530		—		3		46		39		2		4
Restricted cash included in Other deferred debits and other assets	49		49		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	2,120	$	879	$	107	$	845	$	253	$	118	$	81	$	19

Balance at December 31, 2025
Cash and cash equivalents	$	626	$	159	$	116	$	217	$	103	$	22	$	9	$	22
Restricted cash and cash equivalents	525		454		—		3		38		33		3		2
Restricted cash included in Other deferred debits and other assets	50		50		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,201	$	663	$	116	$	220	$	141	$	55	$	12	$	24

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

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2025 Form 10-K.

Supplemental Balance Sheet Information

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

107

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 15 — Supplemental Financial Information


	Accrued expenses
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at September 30, 2026
Compensation-related accruals(a)	$	589	$	201	$	68	$	71	$	109	$	30	$	21	$	16
Taxes accrued	243		102		14		34		125		91		24		10
Interest accrued	495		130		59		108		90		40		28		19
Other accruals(b)	275		9		218		1		32		21		4		8

Balance at December 31, 2025
Compensation-related accruals(a)	$	705	$	209	$	96	$	99	$	125	$	35	$	24	$	17
Taxes accrued	242		94		306		191		107		69		25		18
Interest accrued	538		155		75		55		92		49		18		20

__________

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

(b)Primarily relates to environmental and contingency reserves.

16. 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.

108

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 16 — Related Party Transactions

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,
	2026		2025		2026		2025		2026		2025		2026		2025
Exelon
BSC									$	132	$	156	$	383	$	478
PHISCO									19		29		71		83
ComEd
BSC	$	104	$	95	$	316	$	296	54		63		166		186
PECO
BSC	55		58		188		178		28		24		69		79
BGE
BSC	56		60		193		185		21		28		62		92
PHI
BSC	38		44		154		144		29		41		87		121
PHISCO	—		—		—		—		19		29		71		83
Pepco
BSC	32		30		104		93		10		18		35		52
PHISCO	27		29		94		91		5		14		27		36

DPL
BSC	20		19		65		58		9		12		27		36
PHISCO	22		24		73		75		8		8		23		25

ACE
BSC	16		15		52		47		10		10		23		28
PHISCO	16		22		67		69		7		7		21		22

109

Table of Contents

Combined Notes to Consolidated Financial Statements — (Continued)

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

Note 16 — Related Party Transactions

Receivables from/Payables to Affiliates

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

September 30, 2026


				Receivables from affiliates:
	Payables to affiliates:			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
ComEd					$	—		$	—		$	—		$	—		$	—		$	65		$	—		$	3		$	68
PECO		$	—					—			—			—			—			30			—			5			35
BGE		—			—						—			—			—			33			—			2			35
PHI(a)		—			—			—			—			—			—			6			—			5			11
Pepco		—			—			—						—			—			19			13			2			34
DPL		—			—			—			—						—			12			9			2			23
ACE		—			—			—			—			—						9			8			1			18


Other		5			1			—			—			6			1			—			—						13
Total		$	5		$	1		$	—		$	—		$	6		$	1		$	174		$	30		$	20		$	237

December 31, 2025


				Receivables from affiliates:
	Payables to affiliates:			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
ComEd					$	—		$	—		$	—		$	—		$	—		$	76		$	—		$	5		$	81
PECO		$	—					—			—			—			—			33			—			2			35
BGE		—			—						—			—			—			39			—			—			39
PHI(a)		—			—			—			—			—			—			5			2			11			18
Pepco		—			—			—						—			—			25			11			1			37
DPL		—			—			—			—						—			15			10			—			25
ACE		—			—			—			—			—						14			10			—			24
Other		5			—			1			—			2			12			—			—						20
Total		$	5		$	—		$	1		$	—		$	2		$	12		$	207		$	33		$	19		$	279

__________

(a)PHI is presented exclusive of Pepco, DPL, and ACE, which are included in the table herein.

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, 2026						December 31, 2025
	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

110

Table of Contents

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, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three and nine months ended September 30, 2026 and 2025, see the discussions of Results of Operations by Registrant.


	Three Months Ended September 30,				(Unfavorable) Favorable Variance		Nine Months Ended September 30,				(Unfavorable) Favorable Variance
	2026		2025				2026		2025
Exelon	$	729	$	875	$	(146)	$	2,044	$	2,174	$	(130)
ComEd	406		373		33		965		903		62
PECO	165		250		(85)		562		652		(90)
BGE	90		82		8		443		398		45
PHI	187		291		(104)		465		628		(163)
Pepco	40		156		(116)		173		337		(164)
DPL	61		55		6		164		163		1
ACE	90		82		8		139		138		1
Other(a)	(119)		(121)		2		(391)		(407)		16

__________

(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, 2026 Compared to Three Months Ended September 30, 2025. Net income attributable to common shareholders decreased by $146 million and diluted earnings per average common share decreased to $0.70 in 2026 from $0.86 in 2025 primarily due to:

•Higher write-offs associated with Pepco's Maryland Base Rate Case at PHI;

•Higher storm costs at PECO due to the absence of extraordinary February and June storm cost deferrals recognized in 2025 and increased storm costs;

111

Table of Contents

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

•Higher project impairments at BGE;

•Higher depreciation expense at PECO and PHI;

•Higher income taxes at PECO;

•Higher contracting costs at PECO; and

•Higher storm costs at PHI.

Note that rate increases are associated with updated recovery rates for costs and investments to serve customers. The decreases were partially offset by:

•Favorable impacts of approved rate increases at ComEd, BGE and PHI;

•Higher AFUDC at ComEd;

•Absence of Customer Surcharge Credits at PECO;

•Favorable weather at PECO;

•Lower contracting costs at BGE; and

•Lower income taxes at Exelon Corporate.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net income attributable to common shareholders decreased by $130 million and diluted earnings per average common share decreased to $1.98 in 2026 from $2.15 in 2025 primarily due to:

•Higher write-offs associated with Pepco's Maryland Base Rate Case at PHI;

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

•Higher depreciation expense at PECO and PHI;

•Timing of distribution earnings at ComEd;

•Higher storm costs at PECO due to the absence of extraordinary February and June storm cost deferrals recognized in 2025;

•Higher project impairments at BGE;

•Higher contracting costs at PECO;

•Higher income taxes at PECO;

•Higher credit loss expense at BGE;

•Higher storm costs at PHI; and

•Unfavorable impacts of the Pepco Maryland multi-year plan reconciliation at PHI.

Note that rate increases are associated with updated recovery rates for costs and investments to serve customers, driving top quartile reliability and avoiding outage costs. The decreases were partially offset by:

•Favorable impacts of approved rate increases at ComEd, BGE and PHI;

•Absence of Customer Relief Fund contribution at Exelon Corporate;

•Higher AFUDC at ComEd;

•Absence of Customer Surcharge Credits at PECO;

•Favorable weather at PECO;

•Lower contracting costs at BGE;

•Lower storm costs at PECO; and

•Lower income taxes at Exelon Corporate.

112

Table of Contents

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.

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, 2026 compared to the same period in 2025:



	Three Months Ended September 30,
	2026				2025
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net income attributable to common shareholders	$	729	$	0.70	$	875	$	0.86

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






Change in environmental costs (net of taxes of $1)	(3)		—		—		—
Cost management program (net of taxes of $6)(a)	15		0.01		—		—
Project impairments (net of taxes of $11)(b)	26		0.03		—		—
Regulatory matters (net of taxes of $50)(c)	130		0.13		—		—

Adjusted (non-GAAP) operating earnings	$	897	$	0.87	$	874	$	0.86


	Nine Months Ended September 30,
	2026				2025
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net income attributable to common shareholders	$	2,044	$	1.98	$	2,174	$	2.15





Asset retirement obligation (net of taxes of $0)	—		—		(1)		—
Change in environmental costs (net of taxes of $1)	(3)		—		—		—
Change in FERC audit liability (net of taxes of $1)	—		—		2		—
Cost management program (net of taxes of $21 and $0, respectively)(a)	57		0.06		(1)		—
Income tax-related adjustments (entire amount represents tax expense)(d)	—		—		1		—
Project impairments (net of taxes of $11)(b)	26		0.03		—		—
Regulatory matters (net of taxes of $54 and $7, respectively)(c)	141		0.14		22		0.02

Adjusted (non-GAAP) operating earnings	$	2,265	$	2.20	$	2,198	$	2.17

__________

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 2026 and 2025 ranged from 24.0% to 29.0%.

(a)In 2025, primarily represents severance costs related to a cost management program. In 2026, represents third-party consulting and severance costs related to a cost management program.

(b)Represents costs related to capital project impairments.

(c)Represents the disallowance of certain capitalized costs.

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

113

Table of Contents

Significant 2026 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 2026. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Completed Distribution Base Rate Case Proceedings


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase		Approved ROE	Approval Date	Rate Effective Date
ComEd - Illinois	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
	October 14, 2025 (amended April 16, 2026)	Electric	$	120	$	51	9.40%	August 28, 2026	August 10, 2026
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
	September 20, 2024 (amended September 5, 2025)	Natural Gas	$	37	$	22	9.60%	December 17, 2025	January 1, 2026
ACE - New Jersey	November 21, 2024	Electric	$	109	$	54	9.60%	November 21, 2025	December 1, 2025

114

Table of Contents

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

DPL - Delaware

December 9, 2025 (amended August 31, 2026)

Electric

10.50%

Third quarter of 2027

BGE - Maryland

July 2, 2026
(amended October 16, 2026)

Electric

151

10.40%

First quarter of 2027

Transmission Formula Rates

For 2026, the following increases/(decreases) were included in the Utility Registrants' 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 (Decrease) Increase		Total Revenue Requirement (Decrease) Increase		Allowed Return on Rate Base		Allowed ROE
ComEd	$	31	$	(52)	$	(21)	8.15	%	11.50	%
PECO	$	20	$	20	$	40	7.62	%	10.35	%
BGE	$	16	$	(40)	$	(30)	7.51	%	10.50	%
Pepco	$	12	$	(21)	$	(9)	7.72	%	10.50	%
DPL	$	3	$	1	$	4	7.53	%	10.50	%
ACE	$	1	$	16	$	17	7.26	%	10.50	%

2026 PECO Distribution Base Rate Filing

On April 16, 2026, PECO filed a petition with the PAPUC to withdraw its previously filed electric and gas distribution rate proceedings submitted on March 30, 2026. The PAPUC approved the petition to withdraw the rate cases on April 30, 2026.

PECO will continue to evaluate the timing and approach for future capital investments and potential regulatory filings. Any decisions related to capital investments to support longer-term grid modernization will be informed by customer affordability considerations, system reliability needs, and ongoing engagement with regulators and other stakeholders. As PECO assesses longer-term grid needs, it remains committed to providing safe and reliable service.

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 will now pay the greater of 15.0% of financial statement pre-tax income (with certain adjustments) or their regular federal tax liability, which is federal taxable income multiplied by the 21.0% federal corporate tax rate. 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.

115

Table of Contents

reimbursement from Constellation for $235 million due to the reduction in the amount of Constellation's tax credits needed to offset Exelon's CAMT liability on its amended returns. See Note 7 – Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

The impact of the notice was recorded as of March 31, 2026.

At-the-Market Program

In the third quarter of 2026, Exelon issued approximately 2.3 million shares of Common stock at a weighted-average net price of $43.29 per share. The net proceeds from the issuance were $101 million, which were used for general corporate purposes. See Note 13 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

Other Key Business Drivers and Management Strategies

The following discussion of other key business 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 2025 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 2025 Form 10-K, and Note 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.

Exelon’s Cost Saving Strategy (All Registrants)

In May 2026, Exelon announced plans to identify approximately $350 million of operating and maintenance costs savings at Exelon and the Utility Registrants in 2027. This announcement is a result of Exelon’s continuous focus on the needs of our customers through enhanced efficiency and productivity.

Allocation of Income Taxes to Regulated Utilities (All Registrants)

Legislative and Regulatory Developments

Maryland Utility Relief Act (Exelon, BGE, PHI, Pepco, and DPL)

On May 12, 2026, the Governor of Maryland signed into law legislation that addresses several matters pertaining to electric and gas utilities, including a moratorium on rate cases with forecasted test years until April 1, 2027. Additionally, BGE, Pepco and DPL are required to participate as a member in an RTO effective July 1, 2026, which resulted in a complaint filed on July 2, 2026 against Maryland Transmission Operators, including BGE, Pepco, and DPL, at FERC for the removal of the 50-basis-point incentive adder in the transmission formula rates. The final outcome and resolution of the complaint filing cannot be predicted and the results are not expected to be material to Exelon, BGE, PHI, Pepco, and DPL financial statements.

116

Table of Contents

PJM Cost Allocation Methodology (All Registrants)

On October 7, 2026, FERC issued an order providing additional direction on its March 6, 2026 order. The March 6, 2026, order required PJM to eliminate the de minimis threshold exemption used to allocate certain transmission reliability upgrade costs to the rate zones of PJM Transmission Owners, including the Utility Registrants. FERC also directed PJM to recalculate historical cost allocations beginning June 18, 2015, and, as applicable, pass through additional charges or payments to PJM customers, including the Utility Registrants, as applicable, with interest. The October 6th order also directed that hearing and settlement proceedings be held to determine how PJM should reflect changes in market participants during the 15-year refund and surcharge period. An appeal of FERC's March 6th order remains pending before the United States Court of Appeals for the D.C. Circuit.

The final impact of these proceedings cannot be predicted or reasonably estimated at this time, but could be material to the financial statements.

New Jersey Repeal RTO Adder Bill (Exelon, PHI, and ACE)

On July 7, 2026, the Governor of New Jersey signed into law legislation that addresses several matters pertaining to electric utility companies. As part of the legislation ACE is required to participate as a member in an RTO effective January 1, 2027, which could result in a complaint filed for the removal of the 50-basis-point incentive adder in the transmission formula rates.

Delaware Senate Bill 326 (Exelon, PHI, and DPL)

On July 13, 2026, the Governor of Delaware signed into law legislation that addresses several matters pertaining to public utility companies. As part of the law, DPL’s non-mandatory capital spend eligible to be recovered in rates will be limited to $70 million in each of the years ended 2026 and 2027 unless the spend falls within an exception or the commission orders otherwise. Further, beginning in 2028, DPL’s non-mandatory capital spend eligible to be recovered in rates shall not exceed 5% of DPL’s rate base approved in its most recent base rate case. The legislation also modifies the timing of interim rate recovery in base rate case proceedings. If the DEPSC has not issued a decision within 7 months of a filing, DPL may implement 50% of the proposed rate increase, subject to refund. If no decision has been issued after 12 months, DPL may implement 75% of the proposed increase, also subject to refund. DPL is continuing to evaluate the overall potential impacts of the legislation and will continue to monitor related regulatory developments.

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, 2026, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2025. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2025 Form 10-K for further information.

117

Table of Contents

Results of Operations by Registrant

Results of Operations — ComEd


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2026		2025				2026		2025
Operating revenues	$	2,470	$	2,275	$	195	$	6,368	$	6,176	$	192
Operating expenses
Purchased power	783		806		23		1,814		2,044		230
Operating and maintenance	464		409		(55)		1,350		1,254		(96)
Depreciation and amortization	438		395		(43)		1,258		1,162		(96)
Taxes other than income taxes	133		107		(26)		345		303		(42)
Total operating expenses	1,818		1,717		(101)		4,767		4,763		(4)

Operating income	652		558		94		1,601		1,413		188
Other income and (deductions)
Interest expense, net	(149)		(135)		(14)		(428)		(395)		(33)
Other, net	43		33		10		116		86		30
Total other income and (deductions)	(106)		(102)		(4)		(312)		(309)		(3)
Income before income taxes	546		456		90		1,289		1,104		185
Income taxes	140		83		(57)		324		201		(123)
Net income	$	406	$	373	$	33	$	965	$	903	$	62

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net Income increased by $33 million as compared to the same period in 2025, primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net income increased by $62 million as compared to the same period in 2025, primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC, offset by the timing of distribution earnings.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase		Increase
Distribution	$	33	$	49
Transmission	52		85
Energy efficiency	18		40
Other	7		2
	110		176
Regulatory required programs	85		16
Total increase	$	195	$	192

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.

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 and nine months ended September 30, 2026 as compared to the same periods in 2025, primarily due to higher rate base and higher fully recoverable costs.

118

Table of Contents

ComEd

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 revenues increased for the three and nine months ended September 30, 2026 compared to the same periods in 2025, primarily due to higher rate base and higher fully recoverable costs.

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, 2026 as compared to the same periods in 2025, primarily due to higher fully recoverable costs.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues increased for the three and nine months ended September 30, 2026 as compared to the same periods in 2025, which primarily reflects increased mutual assistance revenues associated with storm restoration efforts.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. 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. One of our larger regulatory required programs is our customer choice program where 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. For customers that choose to purchase electric generation from competitive suppliers, this is treated as a pass through for ComEd and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover costs from customers.

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

The decrease of $23 million and $230 million for the three and nine months ended September 30, 2026, compared to the same periods in 2025, in Purchased Power Expense is offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting, and materials	$	36	$	76
Storm-related costs	(8)		1
BSC costs	8		20
Pension and non-pension postretirement benefits expense	3		8



Other(a)	(6)		(46)
	33		59
Regulatory required programs	22		37
Total increase	$	55	$	96

__________

(a)Primarily reflects the disallowance of certain capitalized costs in regulatory matters during the three months ended March 31, 2025.

119

Table of Contents

ComEd

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


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase		Increase
Depreciation and amortization(a)	$	20	$	51
Regulatory asset amortization	23		45

Total increase	$	43	$	96

__________

(a)Reflects ongoing capital expenditures.

Taxes other than income taxes increased by $26 million and $42 million for the three and nine months ended September 30, 2026, respectively, compared to the same period in 2025, primarily due to increased Assistance Charges for Electricity Distributors and increased utility property taxes.

Interest expense, net increased by $14 million and $33 million for the three and nine months ended September 30, 2026, respectively, compared to the same period in 2025, primarily due to an increase in outstanding debt.

Other, net increased $10 million and $30 million for the three and nine months ended September 30, 2026, respectively, compared to the same periods in 2025, primarily due to higher AFUDC equity.

Effective income tax rates were 25.6% and 18.2% for the three months ended September 30, 2026 and 2025, respectively, and 25.1% and 18.2% for the nine months ended September 30, 2026 and 2025, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

120

Table of Contents

PECO

Results of Operations — PECO


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2026		2025				2026		2025
Operating revenues	$	1,240	$	1,180	$	60	$	3,794	$	3,513	$	281
Operating expenses
Purchased power and fuel	494		446		(48)		1,495		1,288		(207)
Operating and maintenance	313		241		(72)		949		872		(77)
Depreciation and amortization	126		115		(11)		373		336		(37)
Taxes other than income taxes	73		69		(4)		204		183		(21)
Total operating expenses	1,006		871		(135)		3,021		2,679		(342)

Operating income	234		309		(75)		773		834		(61)
Other income and (deductions)
Interest expense, net	(76)		(65)		(11)		(219)		(188)		(31)
Other, net	15		11		4		39		29		10
Total other income and (deductions)	(61)		(54)		(7)		(180)		(159)		(21)
Income before income taxes	173		255		(82)		593		675		(82)
Income taxes	8		5		(3)		31		23		(8)


Net income	$	165	$	250	$	(85)	$	562	$	652	$	(90)

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net Income decreased by $85 million due to higher storm costs, tax repairs, some of which is timing, contracting, depreciation, and interest expense. The higher storm costs reflect the absence of extraordinary February and June storm cost deferrals recognized in the third quarter of 2025 and increased storm costs in the third quarter of 2026. These unfavorable impacts were partially offset by higher revenues, primarily due to the absence of surcharge credits to customers and favorable weather.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net income decreased by $90 million due to higher storm costs, tax repairs, some of which is timing, contracting, depreciation, interest, and severance costs related to the cost management program. The higher storm costs reflect the absence of extraordinary storm cost deferrals recognized in the third quarter of 2025, partially offset by lower storm costs in 2026. These unfavorable impacts were partially offset by higher revenues, primarily due to the absence of surcharge credits to customers and favorable weather.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2026						Nine Months Ended September 30, 2026
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	19	$	—	$	19	$	33	$	7	$	40
Volume	(14)		(1)		(15)		(24)		1		(23)
Pricing	(1)		2		1		4		2		6
Transmission	8		—		8		24		—		24
Other(a)	10		—		10		49		5		54
	22		1		23		86		15		101
Regulatory required programs	36		1		37		158		22		180
Total increase	$	58	$	2	$	60	$	244	$	37	$	281

__________

(a)Other revenues for the three and nine months ended September 30, 2026 increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.

121

Table of Contents

PECO

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2026, compared to the same period in 2025, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.

Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and nine months ended September 30, 2026, compared to the same period in 2025, and normal weather consisted of the following:


	Three Months Ended September 30,			% Change
PECO Service Territory	2026	2025	Normal	2026 vs. 2025		2026 vs. Normal
Heating Degree-Days	12	—	19	N/A		(36.8)	%
Cooling Degree-Days	1,175	1,095	1,038	7.3	%	13.2	%
	Nine Months Ended September 30,			% Change
	2026	2025	Normal	2026 vs. 2025		2026 vs. Normal
Heating Degree-Days	2,732	2,684	2,793	1.8	%	(2.2)	%
Cooling Degree-Days	1,711	1,521	1,426	12.5	%	20.0	%

Volume. Electric volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2026 compared to the same period in 2025, decreased due to customer load. Natural gas volume for the three and nine months ended September 30, 2026, compared to the same period in 2025, 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)
	2026	2025					2026	2025
Residential	4,100	4,063	0.9	%	(4.3)	%	11,094	10,952	1.3	%	(2.0)	%
Small commercial & industrial	2,059	2,057	0.1	%	(4.0)	%	5,811	5,835	(0.4)	%	(2.2)	%
Large commercial & industrial	3,807	3,731	2.0	%	1.9	%	10,365	10,470	(1.0)	%	(1.8)	%
Public authorities & electric railroads	169	159	6.3	%	6.3	%	502	511	(1.8)	%	(1.8)	%
Total electric retail deliveries(a)	10,135	10,010	1.2	%	(1.8)	%	27,772	27,768	—	%	(2.0)	%


	At September 30,
Number of Electric Customers	2026	2025
Residential	1,537,965	1,539,345
Small commercial & industrial	154,259	154,955
Large commercial & industrial	3,133	3,159
Public authorities & electric railroads	10,141	10,343
Total	1,705,498	1,707,802

__________

(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.

122

Table of Contents

PECO


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)
	2026	2025					2026	2025
Residential	2,221	2,064	7.6	%	5.1	%	29,182	28,469	2.5	%	—	%
Small commercial & industrial	1,932	2,243	(13.9)	%	(15.1)	%	16,355	16,046	1.9	%	—	%
Large commercial & industrial	—	—	N/A		(2.6)	%	(9)	14	(164.3)	%	(8.1)	%
Transportation	5,267	5,081	3.7	%	(33.8)	%	18,987	17,759	6.9	%	(2.9)	%
Total natural gas deliveries(a)	9,420	9,388	0.3	%	(0.2)	%	64,515	62,288	3.6	%	2.1	%


	At September 30,
Number of Natural Gas Customers	2026	2025
Residential	511,031	510,166
Small commercial & industrial	44,382	44,603
Large commercial & industrial	7	7
Transportation	600	619
Total	556,020	555,395

__________

(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, 2026, compared to the same period in 2025, remained relatively consistent.

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, 2026, compared to the same period in 2025, increased primarily due to increases in the underlying costs and capital investments.

Other Revenue primarily includes revenue related to late payment charges. Other revenue for the three and nine months ended September 30, 2026, compared to the same period in 2025, increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. 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 Income taxes. One of our larger regulatory required programs is our customer choice program where 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. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for PECO and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover costs from customers.

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

The increase of $48 million and $207 million for the three and nine months ended September 30, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

123

Table of Contents

PECO

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


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting and materials(a)	$	6	$	53
Storm-related costs(b)	81		42
BSC costs	(3)		10
Pension and non-pension postretirement benefit expense	1		4
Credit loss expense	(2)		(6)
Other	3		16
	86		119
Regulatory required programs	(14)		(42)
Total increase	$	72	$	77

__________

(a)Reflects severance related to cost management program.

(b)Increase primarily due to the absence of $53 million deferral for extraordinary February and June storm costs recognized in the third quarter of 2025.

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


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase		Increase (Decrease)
Depreciation and amortization(a)	$	11	$	38
Regulatory asset amortization	—		(1)

Total increase	$	11	$	37

__________

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

Taxes other than income taxes increased by $4 million and $21 million for the three and nine months ended September 30, 2026, respectively, compared to the same period in 2025, primarily due to higher Pennsylvania gross receipts tax.

Interest expense, net increased by $11 million and $31 million for the three and nine months ended September 30, 2026, respectively, compared to the same period in 2025, primarily due to an increase in interest rates and higher outstanding debt.

Effective income tax rates were 4.6% and 2.0% for the three months ended September 30, 2026 and 2025, respectively, and 5.2% and 3.4% for the nine months ended September 30, 2026 and 2025, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

124

Table of Contents

BGE

Results of Operations — BGE


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2026		2025				2026		2025
Operating revenues	$	1,363	$	1,209	$	154	$	4,409	$	3,791	$	618
Operating expenses
Purchased power and fuel	650		568		(82)		2,002		1,584		(418)
Operating and maintenance	292		239		(53)		910		807		(103)
Depreciation and amortization	161		155		(6)		496		473		(23)
Taxes other than income taxes	100		93		(7)		301		273		(28)
Total operating expenses	1,203		1,055		(148)		3,709		3,137		(572)

Operating income	160		154		6		700		654		46
Other income and (deductions)
Interest expense, net	(73)		(64)		(9)		(202)		(183)		(19)
Other, net	26		15		11		64		35		29
Total other income and (deductions)	(47)		(49)		2		(138)		(148)		10
Income before income taxes	113		105		8		562		506		56
Income taxes	23		23		—		119		108		(11)
Net income	$	90	$	82	$	8	$	443	$	398	$	45

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net income increased $8 million primarily due to approved distribution and transmission rates and a decrease in contracting and various operating expenses, partially offset by project impairments.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net income increased $45 million primarily due to approved distribution and transmission rates, the absence of the derecognition of regulatory assets for multi-year plan reconciliations that occurred during the second quarter of 2025, and a decrease in contracting and various operating expenses, partially offset by project impairments, an increase in credit loss expense, and severance costs related to the cost management program.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30,						Nine Months Ended September 30,
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Distribution	$	14	$	7	$	21	$	29	$	36	$	65
Transmission	6		—		6		7		—		7
Other	2		(1)		1		15		1		16
	22		6		28		51		37		88
Regulatory required programs	133		(7)		126		539		(9)		530
Total increase	$	155	$	(1)	$	154	$	590	$	28	$	618

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.

125

Table of Contents

BGE


	At September 30,
Number of Electric Customers	2026	2025
Residential	1,230,325	1,220,937
Small commercial & industrial	115,037	115,246
Large commercial & industrial	13,467	13,432
Public authorities & electric railroads	250	254
Total	1,359,079	1,349,869


	At September 30,
Number of Natural Gas Customers	2026	2025
Residential	663,403	660,241
Small commercial & industrial	37,620	37,731
Large commercial & industrial	6,419	6,404

Total	707,442	704,376

Distribution Revenue increased for the three and nine months ended September 30, 2026, compared to the same period in 2025, due to favorable impacts of the multi-year plans.

Transmission Revenue Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and nine months ended September 30, 2026, compared to the same period in 2025, 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, 2026 as compared to the same period in 2025, primarily driven by increases in late payment charges.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. 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. One of our larger regulatory required programs is our customer choice program where 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. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for BGE and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover costs from customers.

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

The increase of $82 million and $418 million for the three and nine months ended September 30, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

126

Table of Contents

BGE

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


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase (Decrease)		Increase (Decrease)
Project impairments(a)	$	37	$	37
Credit loss expense	(6)		30
BSC costs	(4)		7
Storm-related costs	4		—
Pension and non-pension postretirement benefits expense	(4)		(14)
Labor, other benefits, contracting and materials(b)	(11)		(28)
Other(c)	—		(19)
	16		13
Regulatory required programs(d)	37		90

Total increase	$	53	$	103

__________

(a)See Note 6 — Property, Plant, and Equipment for additional information.

(b)Reflects severance related to cost management program.

(c)Reflects the absence of the derecognition of regulatory assets for multi-year plan reconciliations that occurred during the second quarter of 2025. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.

(d)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.

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


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization	$	7	$	25
Regulatory required programs(a)	2		8
Regulatory asset amortization	(3)		(10)

Total increase	$	6	$	23

__________

(a)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.

Taxes other than income taxes increased by $7 million and $28 million for the three and nine months ended September 30, 2026, compared to the same period in 2025, primarily due to increased property taxes.

Interest expense, net increased $9 million and $19 million for the three and nine months ended September 30, 2026, respectively, compared to the same period in 2025, primarily due to the issuance of debt in the second quarter of 2026.

Other, net increased by $11 million and $29 million for the three and nine months ended September 30, 2026 compared to the same period in 2025, primarily due to increased interest income and higher AFUDC equity.

Effective income tax rates were 20.4% and 21.9% for the three months ended September 30, 2026 and 2025, and 21.2% and 21.3% for the nine months ended September 30, 2026 and 2025. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

127

Table of Contents

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, 2026 compared to the same periods in 2025. See the Results of Operations for Pepco, DPL, and ACE for additional information.


	Three Months Ended September 30,				(Unfavorable) Favorable Variance		Nine Months Ended September 30,				(Unfavorable) Favorable Variance
	2026		2025				2026		2025
PHI	$	187	$	291	$	(104)	$	465	$	628	$	(163)
Pepco	40		156		(116)		173		337		(164)
DPL	61		55		6		164		163		1
ACE	90		82		8		139		138		1
Other(a)	(4)		(2)		(2)		(11)		(10)		(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, 2026 Compared to Three Months Ended September 30, 2025. Net Income decreased by $104 million primarily due to write-offs associated with Pepco's Maryland Base Rate Case and increases in storm costs, depreciation and interest expense, partially offset by an increase in approved distribution rates and favorable weather conditions at DPL.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net Income decreased by $163 million primarily due to write-offs associated with Pepco's Maryland Base Rate Case and multi-year rate plan reconciliation, increases in storm costs, depreciation and interest expense, severance costs related to the cost management program, and various operating expenses, partially offset by an increase in approved distribution rates.

128

Table of Contents

Pepco

Results of Operations — Pepco


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2026		2025				2026		2025
Operating revenues	$	1,127	$	992	$	135	$	2,975	$	2,626	$	349


Operating expenses
Purchased power	450		367		(83)		1,178		942		(236)
Operating and maintenance	354		154		(200)		762		466		(296)
Depreciation and amortization	115		110		(5)		343		321		(22)
Taxes other than income taxes	128		122		(6)		359		344		(15)
Total operating expenses	1,047		753		(294)		2,642		2,073		(569)
Gain on sale of assets	—		—		—		—		1		(1)
Operating income	80		239		(159)		333		554		(221)
Other income and (deductions)
Interest expense, net	(57)		(53)		(4)		(168)		(159)		(9)
Other, net	13		11		2		37		31		6
Total other income and (deductions)	(44)		(42)		(2)		(131)		(128)		(3)
Income before income taxes	36		197		(161)		202		426		(224)
Income taxes	(4)		41		45		29		89		60
Net income	$	40	$	156	$	(116)	$	173	$	337	$	(164)

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net Income decreased by $116 million primarily due to write-offs associated with Pepco's Maryland Base Rate Case, and increases in depreciation and interest expense, partially offset by an increase in approved distribution rates.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net Income decreased by $164 million primarily due to write-offs associated with Pepco's Maryland Base Rate Case and multi-year rate plan reconciliation, increases in depreciation and interest expense, severance costs related to the cost management program, and various operating expenses, partially offset by an increase in approved distribution rates.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase		Increase
Distribution	$	17	$	25
Transmission	4		9
Other	5		10
	26		44
Regulatory required programs	109		305
Total increase	$	135	$	349

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.

129

Table of Contents

Pepco


	At September 30,
Number of Electric Customers in Maryland	2026	2025
Residential	561,882	559,986
Small commercial & industrial	30,545	30,485
Large commercial & industrial	19,080	19,086
Public authorities & electric railroads	183	177
Total	611,690	609,734

Distribution Revenue increased for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to favorable impacts of the 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, 2026, compared to the same periods in 2025, 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. 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. One of our larger regulatory required programs is our customer choice program where 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. For customers that choose to purchase electric generation from competitive suppliers, this is treated as a pass through for Pepco and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the costs from customers.

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

The increase of $83 million and $236 million for the three and nine months ended September 30, 2026, respectively, compared to the same periods in 2025, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase (Decrease)		Increase (Decrease)
Write-offs associated with Maryland rate orders(a)	$	180	$	206
Labor, other benefits, contracting, and materials(b)	(6)		21
BSC and PHISCO costs	1		14
Storm-related costs	4		2
Credit loss expense	3		(1)
Pension and non-pension postretirement benefits expense	—		(1)
Other	—		2
	182		243

Regulatory required programs(c)	18		53
Total increase	$	200	$	296

_________

130

Table of Contents

Pepco

(a)Reflects the write-offs associated with Pepco's Maryland Base Rate Case and multi-year rate plan reconciliation. See Note 2 — Regulatory Matters for additional information.

(b)Reflects severance related to cost management program.

(c)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters for additional information.

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


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase		Increase
Depreciation and amortization(a)	$	4	$	17

Regulatory required programs(b)	1		5
Total increase	$	5	$	22

__________

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

(b)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters additional information.

Taxes other than income taxes increased $6 million and $15 million for the three and nine months ended September 30, 2026, respectively, compared to the same period 2025, primarily due to increases in utility taxes and property taxes.

Interest expense, net increased $4 million and $9 million for the three and nine months ended September 30, 2026, respectively, compared to the same period 2025, primarily due to the issuance of debt in 2026.

Effective income tax rates were (11.1)% and 20.8% for the three months ended September 30, 2026 and 2025, respectively, and 14.4% and 20.9% for the nine months ended September 30, 2026 and 2025, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

131

Table of Contents

DPL

Results of Operations — DPL


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2026		2025				2026		2025
Operating revenues	$	556	$	491	$	65	$	1,632	$	1,460	$	172
Operating expenses
Purchased power and fuel	264		219		(45)		747		637		(110)
Operating and maintenance	108		94		(14)		339		296		(43)
Depreciation and amortization	67		63		(4)		200		189		(11)
Taxes other than income taxes	16		21		5		66		63		(3)
Total operating expenses	455		397		(58)		1,352		1,185		(167)

Operating income	101		94		7		280		275		5
Other income and (deductions)
Interest expense, net	(28)		(26)		(2)		(81)		(75)		(6)
Other, net	7		4		3		14		12		2
Total other income and (deductions)	(21)		(22)		1		(67)		(63)		(4)
Income before income taxes	80		72		8		213		212		1
Income taxes	19		17		(2)		49		49		—
Net income	$	61	$	55	$	6	$	164	$	163	$	1

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net income increased by $6 million primarily due to favorable weather conditions at Delaware electric and natural gas service territories, an increase in approved Delaware electric distribution and natural gas rates, and a decrease in property taxes partially offset by an increase in storm costs.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net income remained relatively consistent.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2026						Nine Months Ended September 30, 2026
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	3	$	—	$	3	$	6	$	2	$	8
Volume	1		(1)		—		2		(2)		—
Distribution	3		2		5		11		12		23
Transmission	3		—		3		8		—		8
Other	—		—		—		(1)		—		(1)
	10		1		11		26		12		38
Regulatory required programs	43		11		54		98		36		134
Total increase	$	53	$	12	$	65	$	124	$	48	$	172

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

132

Table of Contents

DPL

weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and nine months ended September 30, 2026 compared to the same period in 2025, 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, 2026, compared to same periods in 2025 and normal weather consisted of the following:


	Three Months Ended September 30,			% Change
Delaware Electric Service Territory	2026	2025	Normal	2026 vs. 2025		2026 vs. Normal
Heating Degree-Days	28	3	27	833.3	%	3.7	%
Cooling Degree-Days	981	897	923	9.4	%	6.3	%

	Nine Months Ended September 30,			% Change
Delaware Electric Service Territory	2026	2025	Normal	2026 vs. 2025		2026 vs. Normal
Heating Degree-Days	2,934	2,774	2,871	5.8	%	2.2	%
Cooling Degree-Days	1,393	1,296	1,273	7.5	%	9.4	%


	Three Months Ended September 30,			% Change
Delaware Natural Gas Service Territory	2026	2025	Normal	2026 vs. 2025		2026 vs. Normal
Heating Degree-Days	28	3	32	833.3	%	(12.5)	%

	Nine Months Ended September 30,			% Change
Delaware Natural Gas Service Territory	2026	2025	Normal	2026 vs. 2025		2026 vs. Normal
Heating Degree-Days	2,934	2,774	2,957	5.8	%	(0.8)	%

Volume, exclusive of the effects of weather, remained relatively consistent for the three and nine months ended September 30, 2026 compared to the same periods in 2025.


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)
	2026	2025					2026	2025
Residential	980	928	5.6	%	1.8	%	2,647	2,533	4.5	%	1.9	%
Small commercial & industrial	404	389	3.9	%	2.1	%	1,125	1,112	1.2	%	0.1	%
Large commercial & industrial	806	873	(7.7)	%	(8.6)	%	2,247	2,329	(3.5)	%	(3.9)	%
Public authorities & electric railroads	6	8	(25.0)	%	(24.7)	%	(4)	23	(117.4)	%	(117.1)	%
Total electric retail deliveries(a)	2,196	2,198	(0.1)	%	(2.3)	%	6,015	5,997	0.3	%	(1.2)	%


	At September 30,
Number of Total Electric Customers (Maryland and Delaware)	2026	2025
Residential	497,718	494,232
Small commercial & industrial	65,857	65,322
Large commercial & industrial	1,287	1,257
Public authorities & electric railroads	631	632
Total	565,493	561,443

133

Table of Contents

DPL

__________

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

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


Natural Gas Retail Deliveries to Delaware Customers (in mmcf)	Three Months Ended September 30,		% Change		Weather - Normal % Change(b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change(b)
	2026	2025					2026	2025
Residential	405	409	(1.0)	%	(9.3)	%	5,812	5,802	0.2	%	(3.8)	%
Small commercial & industrial	368	375	(1.9)	%	(6.9)	%	2,979	2,881	3.4	%	(0.9)	%
Large commercial & industrial	411	404	1.7	%	1.8	%	1,239	1,237	0.2	%	0.2	%
Transportation	1,146	1,239	(7.5)	%	(8.3)	%	4,443	4,626	(4.0)	%	(5.3)	%
Total natural gas deliveries(a)	2,330	2,427	(4.0)	%	(6.6)	%	14,473	14,546	(0.5)	%	(3.4)	%


	At September 30,
Number of Delaware Natural Gas Customers	2026	2025
Residential	132,182	131,494
Small commercial & industrial	10,188	10,134
Large commercial & industrial	14	14
Transportation	156	160
Total	142,540	141,802

__________

(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 remained relatively consistent for the three months ended September 30, 2026 compared to the same period in 2025. During the nine months ended September 30, 2026, compared to the same period in 2025, distribution revenue increased primarily due to Delaware natural gas rates that became effective in 2025 & electric distribution rates that became effective in 2026.

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, 2026 compared to the same period in 2025, 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. The riders are designed to provide full and current cost recovery as well as a return in certain instances. One of our larger regulatory required programs is our customer choice program where customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for DPL and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover costs from customers.

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

The increase of $45 million and $110 million for the three and nine months ended September 30, 2026, respectively, compared to the same periods in 2025 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

134

Table of Contents

DPL

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


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting, and materials(a)	$	1	$	12
BSC and PHISCO costs	(1)		5
Storm-related costs	5		8
Credit loss expense	2		(1)

Other	(1)		—
	6		24
Regulatory required programs(b)	8		19
Total increase	$	14	$	43

__________

(a)Reflects severance related to the cost management program.

(b)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — 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, 2026		Nine Months Ended September 30, 2026
	Increase		Increase (Decrease)
Depreciation and amortization(a)	$	4	$	11
Regulatory asset amortization	—		(1)
Regulatory required programs(b)	—		1
Total increase	$	4	$	11

__________

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

Taxes other than income taxes decreased by $5 million for the three months ended September 30, 2026, compared to the same period in 2025 primarily due to a decrease in property taxes. For the nine months ended September 30, 2026 compared to the same period in 2025 taxes other than income taxes remained relatively consistent.

Interest Expense, net increased by $2 million and $6 million for the three and nine months ended September 30, 2026, respectively, compared to the same period in 2025 primarily due to the issuance of debt in 2026.

Effective income tax rates were 23.8% and 23.6% for the three months ended September 30, 2026 and 2025, respectively, and 23.0% and 23.1% for the nine months ended September 30, 2026 and 2025, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

135

Table of Contents

ACE

Results of Operations — ACE


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2026		2025				2026		2025
Operating revenues	$	579	$	570	$	9	$	1,402	$	1,328	$	74


Operating expenses
Purchased power	276		286		10		668		616		(52)
Operating and maintenance	92		92		—		285		277		(8)
Depreciation and amortization	67		61		(6)		195		188		(7)
Taxes other than income taxes	2		2		—		8		7		(1)
Total operating expenses	437		441		4		1,156		1,088		(68)

Operating income	142		129		13		246		240		6
Other income and (deductions)
Interest expense, net	(23)		(20)		(3)		(67)		(62)		(5)
Other, net	3		2		1		8		8		—
Total other income and (deductions)	(20)		(18)		(2)		(59)		(54)		(5)
Income before income taxes	122		111		11		187		186		1
Income taxes	32		29		3		48		48		—
Net income	$	90	$	82	8		$	139	$	138	$	1

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. Net income increased by $8 million primarily due to an increase in approved distribution rates, partially offset by an increase in storm costs, interest and depreciation expense.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. Net income remained relatively consistent.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase (Decrease)		Increase
Distribution	$	16	$	23
Transmission	3		12

	19		35
Regulatory required programs	(10)		39
Total increase	$	9	$	74

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.

136

Table of Contents

ACE


	At September 30,
Number of Electric Customers	2026	2025
Residential	512,248	509,739
Small commercial & industrial	63,063	62,923
Large commercial & industrial	2,663	2,730
Public authorities & electric railroads	782	745
Total	578,756	576,137

Distribution Revenue increased for the three and nine months ended September 30, 2026 compared to the same periods in 2025 due to approved distribution rates that became effective in December 2025 as well as 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 increased for the three and nine months ended September 30, 2026 compared to the same periods in 2025 primarily due to increases in underlying costs and capital investment.

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. The riders are designed to provide full and current cost recovery as well as a return in certain instances. One of our larger regulatory required programs is our customer choice program where 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. For customers that choose to purchase electric generation from competitive suppliers, this is treated as a pass through for ACE and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover costs from customers.

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

The decrease of $10 million and increase $52 million for the three and nine months ended September 30, 2026, respectively, compared to the same periods in 2025 in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

137

Table of Contents

ACE

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


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase (Decrease)		Increase (Decrease)
Storm-related costs	$	5	$	8
Credit loss expense	2		—
Labor, other benefits, contracting, and materials(a)	(4)		2
BSC and PHISCO costs	(3)		1
Pension and non-pension postretirement benefits expense	—		(1)
Other	1		3
	1		13
Regulatory required programs	(1)		(5)
Total increase	$	—	$	8

_________

(a)Reflects severance related to cost management program.

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


	Three Months Ended September 30, 2026		Nine Months Ended September 30, 2026
	Increase		Increase (Decrease)
Depreciation and amortization(a)	$	1	$	6
Regulatory asset amortization	4		12
Regulatory required programs	1		(11)
Total increase	$	6	$	7

__________

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

Interest expense, net increased $3 million and $5 million for the three and nine months ended September 30, 2026, respectively, compared to the same period 2025, primarily due to the issuance of debt in 2026.

Effective income tax rates were 26.2% and 26.1% for the three months ended September 30, 2026 and 2025, respectively, and 25.7% and 25.8% for the nine months ended September 30, 2026 and 2025, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

138

Table of Contents

Liquidity and Capital Resources (All Registrants)

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

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $4.0 billion. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

Cash Flows 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 2 — Regulatory Matters of the 2025 Form 10-K and Notes 2 — Regulatory Matters and 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.

139

Table of Contents

The following table provides a summary of the change in cash flows from operating activities for the nine months ended September 30, 2026 and 2025 by Registrant:


Increase (decrease) in cash flows from operating activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net (loss) income	$	(130)	$	62	$	(90)	$	45	$	(163)	$	(164)	$	1	$	1
Adjustments to reconcile net income to cash:
Non-cash operating activities	200		(180)		357		195		235		165		18		50

Collateral received (paid), net	64		22		(6)		(2)		37		7		(1)		30
Income taxes	(155)		(60)		(282)		(195)		11		27		(6)		(2)
Pension and non-pension postretirement benefit contributions	(57)		(31)		(2)		(7)		(12)		—		—		(12)
Regulatory assets and liabilities, net	(673)		(898)		(22)		156		72		53		33		(16)
Changes in working capital and other assets and liabilities	1,145		1,119		32		(177)		71		9		53		(14)
Increase (decrease) in cash flows from operating activities	$	394	$	34	$	(13)	$	15	$	251	$	97	$	98	$	37

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 changes in cash flows from operating activities were primarily due to the following:

•See Note 15 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.

•Changes in collateral depended upon whether 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, 2026 to the nine months ended September 30, 2025. See Note 9 — Derivative Financial Instruments for additional information.

•See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.

•Changes in Pension and non-pension postretirement benefit contributions relates to Exelon's increased contributions to the Qualified Plans during the nine months ended September 30, 2026. See Note 12 — Retirement Benefits of the 2025 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. ComEd recognized a reduction in regulatory liabilities of $670 million and an increase in regulatory assets of $9 million related to CMCs for the nine months ended September 30, 2026 and a decrease in regulatory assets of $84 million related to CMCs for the nine months ended September 30, 2025. Included within the change in 2026 are payments for CMC nuclear production tax credits, which relate to a decrease in Accounts Receivable. ComEd's energy efficiency program recognized changes of $330 million and $311 million for the nine months ended September 30, 2026 and 2025, respectively. Additionally, ComEd recognized changes in the distributed generation rebates programs of $101 million and $63 million for the nine months ended September 30, 2026 and 2025, respectively. Also included within the changes is energy efficiency

140

Table of Contents

and demand response programs spend for DPL and ACE of $3 million and $64 million for the nine months ended September 30, 2026, and $11 million and $37 million for the nine months ended September 30, 2025, respectively. BGE and Pepco had no energy efficiency and demand response programs spend recorded to the regulatory asset for the nine months ended September 30, 2026 and $64 million and $27 million, respectively, for the nine months ended September 30, 2025. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the nine months ended September 30, 2026 and 2025.

•Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $1,022 million and $1,145 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, 2026, the established pricing has resulted in ComEd receiving payments from nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in Accounts receivable. This change corresponds to a change in the Carbon mitigation credit regulatory mechanism. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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, 2026 and 2025 by Registrant:


(Decrease) increase in cash flows from investing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	(704)	$	(552)	$	(135)	$	(13)	$	31	$	(57)	$	(27)	$	(47)



Proceeds from sales of assets	(2)		—		—		—		(2)		(2)		—		—
Changes in intercompany money pool	—		—		(79)		—		—		(24)		—		—

Other investing activities	19		3		(11)		—		5		3		1		1
(Decrease) increase in cash flows from investing activities	$	(687)	$	(549)	$	(225)	$	(13)	$	34	$	(80)	$	(26)	$	(46)

Significant changes in cash flows from investing activities were primarily due to the following:

•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.

141

Table of Contents

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, 2026 and 2025 by Registrant:


Increase (decrease) in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	1,101	$	36	$	192	$	175	$	(248)	$	(166)	$	(50)	$	(32)
Long-term debt, net	(1,293)		200		(300)		(75)		50		25		25		—
Changes in intercompany money pool	—		—		—		—		15		—		—		24
Issuance of common stock	310		—		—		—		—		—		—		—
Dividends paid on common stock	(82)		(44)		—		(47)		—		105		30		3

Distributions to member	—		—		—		—		138		—		—		—
Contributions from parent/member	—		272		16		(59)		(83)		86		6		(5)

Other financing activities	17		(8)		5		(2)		(2)		—		1		—
Increase (decrease) in cash flows from financing activities	$	53	$	456	$	(87)	$	(8)	$	(130)	$	50	$	12	$	(10)

Significant changes in cash flows from financing activities were primarily due to the following:

•Changes in short-term borrowings, net, are driven by repayments on and issuances of notes due in less than 365 days. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants.

•Long-term debt, net, varies due to debt issuances and redemptions each year. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the "Debt" 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 second and third quarter of 2026. See Note 13 — 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 16 — Commitments and Contingencies of the 2025 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.

Debt

See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

During the nine months ended September 30, 2026, the following long-term debt was retired and/or redeemed:


Company	Type	Interest Rate		Maturity	Amount
Exelon	Senior Notes	3.40	%	April 15, 2026	$	750
ComEd	First Mortgage Bonds	2.55	%	June 15, 2026	$	500
BGE	Senior Notes	2.40	%	August 15, 2026	$	350

142

Table of Contents

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 2026 and for the fourth quarter of 2026 were as follows:

Period

Declaration Date

Shareholder of Record Date

Dividend Payable Date

Cash per Share(a)

First Quarter 2026

February 12, 2026

March 2, 2026

March 13, 2026

0.4200

Second Quarter 2026

April 28, 2026

June 4, 2026

June 15, 2026

0.4200

Third Quarter 2026

July 28, 2026

September 4, 2026

September 15, 2026

0.4200

Fourth Quarter 2026

October 30, 2026

December 4, 2026

December 15, 2026

0.4200

__________

(a)Exelon's Board of Directors approved an updated dividend policy for 2026. The 2026 quarterly dividend will be $0.42 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 $3.5 billion was available to support additional commercial paper as of September 30, 2026, and of which 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, 2026 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the 2025 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 Program


Effective Period	Shares Issued (in millions)	Weighted-Average Net Price		Net Proceeds (a) (in millions)
Q2 2026 (b)	8.7	$	44.03	$	382
Q3 2026 (c)	2.3	$	43.29	$	101

_________

(a)Proceeds were used for general corporate purposes.

(c)In the third quarter of 2026, Exelon settled a forward sale agreement with a December 15, 2026 maturity date that was entered into by the forward seller under the ATM program as outlined below.

143

Table of Contents


Effective Period	Shares Available (in millions)	Weighted-Average Net Price		Maturity Date
Q1 2026	5.4	$	47.67	July 30, 2027
Q1 2026	6.4	$	48.68	September 2, 2027

Additionally, the following forward sale agreements were entered into during the twelve months ended 2025 under Exelon’s ATM program and were not settled as of December 31, 2025:


Effective Period	Shares Available (in millions)	Weighted-Average Net Price		Maturity Date
Q2 2025	3.6	$	43.17	November 16, 2026
Q3 2025	11.5	$	43.73	December 15, 2026
Q4 2025	0.8	$	45.42	December 15, 2026

Inclusive of the impact of the forward sale agreements, $1.0 billion of Common stock remained available for sale pursuant to the ATM program as of September 30, 2026.

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, 2026 and available credit facility capacity prior to any incremental collateral at September 30, 2026:


	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	36	$	—	$	985
PECO	7		26		596
BGE	12		14		573

Pepco	—		—		297
DPL	—		10		299
ACE	—		—		298

__________

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

144

Table of Contents

Capital Expenditure Spending

As of September 30, 2026, the most recent estimates of capital expenditures for plant additions and improvements for 2026 are as follows:


(In millions)	Transmission	Distribution	Gas	Total(a)
Exelon	N/A	N/A	N/A	$	9,900
ComEd	1,100	2,400	N/A	3,500
PECO	450	1,325	400	2,175
BGE	1,075	575	525	2,175
PHI	725	1,250	50	2,050
Pepco	325	650	N/A	975
DPL	225	325	50	625
ACE	175	275	N/A	450

__________

(a)Numbers rounded to the nearest $25M and may not sum due to rounding.

Projected capital expenditures and other investments to serve customers are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Retirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $325 million in 2026. 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 12 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2025 Form 10-K for additional information on pension and OPEB contributions.

145

Table of Contents

Credit Facilities

See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short-term borrowing activity.

Security Ratings

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.

The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for Exelon, ComEd, PHI, Pepco, DPL, and ACE did not change for the nine months ended September 30, 2026. On April 30, 2026, S&P lowered its long-term issuer credit rating and senior unsecured debt rating for BGE from 'A' to 'A-', and its short-term commercial paper rating for BGE from 'A-1' to 'A-2'. On July 15, 2026, Moody's lowered PECO's long-term issuer rating from 'A2' to 'A3', its senior secured debt rating from 'Aa3' to 'A1', and short-term commercial paper rating from 'P-1' to 'P-2'.

146

Table of Contents

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, 2026, are presented in the following table:


	During the Nine Months Ended September 30, 2026				At September 30, 2026
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	510	$	—	$	96
PECO	383		(63)		301
BSC	—		(461)		(354)
PHI Corporate	—		(134)		(96)
PCI	65		—		53


	During the Nine Months Ended September 30, 2026				At September 30, 2026
PHI Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Pepco	$	116	$	—	$	24
DPL	—		(85)		—
ACE	—		(73)		(24)

Shelf Registration Statements

On February 13, 2025, Exelon and ComEd filed a combined shelf registration statement on Form S-3 registering $12.6 billion in aggregate amount of securities, which was declared effective by the SEC on April 8, 2025. The shelf registration statement may be used to issue Exelon debt and equity securities as well as ComEd debt securities through the expiration date of April 8, 2028. On February 21, 2024, PECO and BGE 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. The ability of Exelon, ComEd, PECO and BGE to sell securities off their corresponding registration statements 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.

147

Table of Contents

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, 2026

Short-term Financing Authority

Remaining Long-term Financing Authority

Commission

Expiration Date

Amount

Commission

Expiration Date

Amount

ComEd(c)

FERC

December 31, 2027

2,500

ICC

January 1, 2027, May 1, 2027, & January 1, 2029

2,968

PECO

FERC

December 31, 2027

1,500

PAPUC

December 31, 2027

1,100

BGE

FERC

December 31, 2027

900

MDPSC

N/A

925

Pepco(a)

FERC

December 31, 2027

700

MDPSC / DCPSC

December 31, 2028

800

DPL(a)

FERC

December 31, 2027

700

MDPSC / DEPSC

December 31, 2028

550

ACE(b)

NJBPU

January 1, 2028

350

NJBPU

December 31, 2026

525

__________

(a)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, 2028.

(b)On June 4, 2026, ACE filed an application with the NJBPU to extend its long-term financing authority through December 31, 2028. ACE expects approval of its application by November 20, 2026.

(c)On October 15, 2026, ComEd filed an application with the ICC requesting authority to refinance up to $900 million of existing indebtedness. ComEd requested approval of its application by January 22, 2027.

148

Table of Contents

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

The Registrants hold commodity and financial instruments that are exposed to the following market risks:

•Commodity price risk, which is discussed further below.

•Counterparty credit risk associated with non-performance by counterparties on executed derivative instruments and participation in all, or some of the established, wholesale spot energy markets that are administered by PJM. The credit policies of PJM may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of counterparty credit risk related to derivative instruments.

•Equity price and interest rate risk associated with Exelon’s pension and OPEB plan trusts. See Note 12 — Retirement Benefits of the 2025 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 hybrid, convertible, fixed-rate and variable-rate debt to manage interest rate exposure. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. In addition, Exelon Corporate 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 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

The Utility 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 Board of Directors, Exelon's Audit and Risk Committee, and/or the applicable Utility Board Registrant. The Registrants do not execute derivatives for speculative or proprietary trading purposes.

Commodity Price Risk (All Registrants)

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon 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.

For additional information on these contracts, see Note 2 — Regulatory Matters and Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

149

Table of Contents

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 liabilities. Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract liabilities giving an indication of when these mark-to-market amounts will settle and require cash. See Note 11 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.


	Maturities Within												Total Fair Value
Commodity derivative contracts(a):	2026		2027		2028		2029		2030		2031 and Beyond		Total Fair Value
Prices based on model or other valuation methods (Level 3)	$	(8)	$	(20)	$	(20)	$	(21)	$	(20)	$	(28)	$	(117)

_________

(a)Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

Credit Risk (All Registrants)

Credit risk for the Utility Registrants is governed by credit and collection policies, which are aligned with state regulatory requirements. The Utility Registrants are currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record an allowance for credit losses, based upon historical experience, current information, and forward-looking risk factors, to provide for the potential loss from nonpayment by these customers. The Utility Registrants will monitor nonpayment from customers and will make any necessary adjustments to the allowance for credit losses. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements of the 2025 Form 10-K for the allowance for credit losses policy. The Utility Registrants did not have any customers representing over 10% of their revenues as of September 30, 2026. See Note 2 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.

ITEM 4. CONTROLS AND PROCEDURES

During the third quarter of 2026, each of the Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures (as defined in Exchange Act Rules 13a‑15(e) and 15d‑15(e)) as of the end of the period covered by this report, pursuant to Exchange Act Rules 13a‑15(b) and 15d‑15(b). 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, 2026, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective (Item 307 of Regulation S‑K).

Changes in Internal Control Over Financial Reporting

The Registrants continually strive to improve disclosure controls and procedures to enhance the quality of financial reporting and to maintain dynamic systems that change as conditions warrant. During the first quarter of 2026, a new ERP system was implemented for a majority of the financial accounting systems, which is expected to improve the efficiency of certain financial and related transaction processes. As part of the implementation of the ERP, the Registrants modified certain existing internal controls and implemented certain new controls in order to align the financial accounting processes with the new ERP system. The Registrants do not believe that any of these modifications or new controls have materially affected, or are reasonably likely to affect, internal control

150

Table of Contents

over financial reporting. There have been no other changes in internal control over financial reporting that occurred during the three and nine months ended September 30, 2026, that have 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 2025 Form 10-K, (b) Notes 2 — Regulatory Matters and 16 — Commitments and Contingencies of the 2025 Form 10-K, and (c) Notes 2 — Regulatory Matters and 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.

ITEM 1A. RISK FACTORS

Risks Related to All Registrants

At September 30, 2026, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2025 Form 10-K in ITEM 1A. RISK FACTORS.

ITEM 5. OTHER INFORMATION

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, 2026.

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-Sixth Supplemental Indenture dated as of July 15, 2026 from PECO to U.S. Bank National Association, as trustee	File No. 000-16844, Form 8-K dated August 10, 2026, Exhibit 4.1

151

Table of Contents

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, 2026 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 Robert A. Kleczynski 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 Michael A. Innocenzo 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, 2026 filed by the following officers for the following companies:

152

Table of Contents


Exelon Corporation
Exhibit No.			Description
32-1			Filed by Calvin G. Butler, Jr. for Exelon Corporation

32-2			Filed by Robert A. Kleczynski 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 Michael A. Innocenzo 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)

153

Table of Contents

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/ ROBERT A. KLECZYNSKI
Calvin G. Butler, Jr.						Robert A. Kleczynski
President, Chief Executive Officer (Principal Executive Officer), and Director						Executive Vice President, Chief Financial Officer (Principal Financial Officer)

/s/ CAROLINE FULGINITI
Caroline Fulginiti
Vice President and Controller (Principal Accounting Officer)

October 30, 2026

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.

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)

October 30, 2026

155

Table of Contents

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PECO ENERGY COMPANY


/s/ MICHAEL A. INNOCENZO						/s/ MARISSA E. HUMPHREY
Michael A. Innocenzo						Marissa E. Humphrey
Interim 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)

October 30, 2026

156

Table of Contents

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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/ CAROLINE FULGINITI
Caroline Fulginiti
Vice President and Controller, Exelon (Principal Accounting Officer, BGE)

October 30, 2026

157

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.

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)

October 30, 2026

158

Table of Contents

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

POTOMAC ELECTRIC POWER COMPANY


/s/ J. TYLER ANTHONY						/s/ 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)

October 30, 2026

159

Table of Contents

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DELMARVA POWER & LIGHT COMPANY


/s/ J. TYLER ANTHONY						/s/ 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)

October 30, 2026

160

Table of Contents

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

ATLANTIC CITY ELECTRIC COMPANY


/s/ J. TYLER ANTHONY						/s/ 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)