Pepco 10-Q 2024 Q3 Quarterly report

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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, 2024

or

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

Commission File Number	Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number
001-16169	EXELON CORPORATION	23-2990190
	(a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (800) 483-3220
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	x	Accelerated Filer	☐	Non-accelerated Filer	☐	Smaller Reporting Company	☐	Emerging Growth Company	☐
Commonwealth Edison Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
PECO Energy Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Baltimore Gas and Electric Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Pepco Holdings LLC	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Potomac Electric Power Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Delmarva Power & Light Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Atlantic City Electric Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐

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

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

The number of shares outstanding of each registrant’s common stock as of September 30, 2024 was:

Exelon Corporation Common Stock, without par value	1,004,833,655
Commonwealth Edison Company Common Stock, $12.50 par value	127,021,416
PECO Energy Company Common Stock, without par value	170,478,507
Baltimore Gas and Electric Company Common Stock, without par value	1,000
Pepco Holdings LLC	not applicable
Potomac Electric Power Company Common Stock, $0.01 par value	100
Delmarva Power & Light Company Common Stock, $2.25 par value	1,000
Atlantic City Electric Company Common Stock, $3.00 par value	8,546,017

TABLE OF CONTENTS

		Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS		4
FILING FORMAT		7
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION		7
WHERE TO FIND MORE INFORMATION		7
PART I.	FINANCIAL INFORMATION	8
ITEM 1.	FINANCIAL STATEMENTS	8
	Exelon Corporation
	Consolidated Statements of Operations and Comprehensive Income	9
	Consolidated Statements of Cash Flows	10
	Consolidated Balance Sheets	11
	Consolidated Statements of Changes in Shareholders’ Equity	13
	Commonwealth Edison Company
	Consolidated Statements of Operations and Comprehensive Income	15
	Consolidated Statements of Cash Flows	16
	Consolidated Balance Sheets	17
	Consolidated Statements of Changes in Shareholders' Equity	19
	PECO Energy Company
	Consolidated Statements of Operations and Comprehensive Income	20
	Consolidated Statements of Cash Flows	21
	Consolidated Balance Sheets	22
	Consolidated Statements of Changes in Shareholder's Equity	24
	Baltimore Gas and Electric Company
	Statements of Operations and Comprehensive Income	25
	Statements of Cash Flows	26
	Balance Sheets	27
	Statements of Changes in Shareholder's Equity	29
	Pepco Holdings LLC
	Consolidated Statements of Operations and Comprehensive Income	30
	Consolidated Statements of Cash Flows	31
	Consolidated Balance Sheets	32
	Consolidated Statements of Changes in Member's Equity	34

1

	Page No.
Potomac Electric Power Company
Statements of Operations and Comprehensive Income	35
Statements of Cash Flows	36
Balance Sheets	37
Statements of Changes in Shareholder's Equity	39
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income	40
Statements of Cash Flows	41
Balance Sheets	42
Statements of Changes in Shareholder’s Equity	44
Atlantic City Electric Company
Consolidated Statements of Operations and Comprehensive Income	45
Consolidated Statements of Cash Flows	46
Consolidated Balance Sheets	47
Consolidated Statements of Changes in Shareholder’s Equity	49
Combined Notes to Consolidated Financial Statements
1. Significant Accounting Policies	50
2. Regulatory Matters	51
3. Revenue from Contracts with Customers	59
4. Segment Information	61
5. Accounts Receivable	70
6. Income Taxes	72
7. Retirement Benefits	75
8. Derivative Financial Instruments	77
9. Debt and Credit Agreements	81
10. Fair Value of Financial Assets and Liabilities	84
11. Commitments and Contingencies	91
12. Shareholders' Equity	99
13. Changes in Accumulated Other Comprehensive Income	99
14. Supplemental Financial Information	100
15. Related Party Transactions	104

2

		Page No.
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	107
	Exelon Corporation	107
	Executive Overview	107
	Financial Results of Operations	107
	Significant 2024 Transactions and Developments	110
	Other Key Business Drivers and Management Strategies	112
	Critical Accounting Policies and Estimates	113
	Results of Operations By Registrant	114
	Commonwealth Edison Company	114
	PECO Energy Company	117
	Baltimore Gas and Electric Company	121
	Pepco Holdings LLC	124
	Potomac Electric Power Company	125
	Delmarva Power & Light Company	128
	Atlantic City Electric Company	133
	Liquidity and Capital Resources	136
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	144
ITEM 4.	CONTROLS AND PROCEDURES	145
PART II.	OTHER INFORMATION	145
ITEM 1.	LEGAL PROCEEDINGS	145
ITEM 1A.	RISK FACTORS	145
ITEM 5.	OTHER INFORMATION	146
ITEM 6.	EXHIBITS	146
SIGNATURES		149
	Exelon Corporation	149
	Commonwealth Edison Company	150
	PECO Energy Company	151
	Baltimore Gas and Electric Company	152
	Pepco Holdings LLC	153
	Potomac Electric Power Company	154
	Delmarva Power & Light Company	155
	Atlantic City Electric Company	156

3

GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon	Exelon Corporation
ComEd	Commonwealth Edison Company
PECO	PECO Energy Company
BGE	Baltimore Gas and Electric Company
Pepco Holdings or PHI	Pepco Holdings LLC
Pepco	Potomac Electric Power Company
DPL	Delmarva Power & Light Company
ACE	Atlantic City Electric Company
Registrants	Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively
Utility Registrants	ComEd, PECO, BGE, Pepco, DPL, and ACE, collectively
BSC	Exelon Business Services Company, LLC
Exelon Corporate	Exelon in its corporate capacity as a holding company
PCI	Potomac Capital Investment Corporation and its subsidiaries
PECO Trust III	PECO Energy Capital Trust III
PECO Trust IV	PECO Energy Capital Trust IV
PHI Corporate	PHI in its corporate capacity as a holding company
PHISCO	PHI Service Company
Former Related Entities
Constellation	Constellation Energy Corporation
Generation	Constellation Energy Generation, LLC (formerly Exelon Generation Company, LLC, a subsidiary of Exelon prior to separation on February 1, 2022)

4

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note - of the 2023 Form 10-K	Reference to specific Combined Note to Consolidated Financial Statements within Exelon's 2023 Annual Report on Form 10-K
ABO	Accumulated Benefit Obligation
AFUDC	Allowance for Funds Used During Construction
AMI	Advanced Metering Infrastructure
AOCI	Accumulated Other Comprehensive Income (Loss)
ARO	Asset Retirement Obligation
ATM	At the market
BGS	Basic Generation Service
BSA	Bill Stabilization Adjustment
CEJA	Climate and Equitable Jobs Act; Illinois Public Act 102-0662 signed into law on September 15, 2021
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended
CIP	Conservation Incentive Program
CMC	Carbon Mitigation Credit
CODMs	Chief Operating Decision Makers
DC PLUG	District of Columbia Power Line Undergrounding Initiative
DCPSC	Public Service Commission of the District of Columbia
DEPSC	Delaware Public Service Commission
DOEE	District of Columbia Department of Energy & Environment
DPA	Deferred Prosecution Agreement
DSIC	Distribution System Improvement Charge
EDIT	Excess Deferred Income Taxes
EIMA	Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EPA	United States Environmental Protection Agency
ERISA	Employee Retirement Income Security Act of 1974, as amended
ETAC	Energy Transition Assistance Charge
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles in the United States
GCR	Gas Cost Rate
GSA	Generation Supply Adjustment
GWhs	Gigawatt hours
ICC	Illinois Commerce Commission
IIJA	Infrastructure Investment and Jobs Act
Illinois Settlement Legislation	Legislation enacted in 2007 affecting electric utilities in Illinois
IPA	Illinois Power Agency
IRA	Inflation Reduction Act
IRC	Internal Revenue Code
IRS	Internal Revenue Service
MDPSC	Maryland Public Service Commission
MGP	Manufactured Gas Plant
mmcf	Million Cubic Feet
MRP	Multi-Year Rate Plan
MWh	Megawatt hour

5

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
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
NPS	National Park Service
NRD	Natural Resources Damages
OCI	Other Comprehensive Income
OPEB	Other Postretirement Employee Benefits
PAPUC	Pennsylvania Public Utility Commission
PGC	Purchased Gas Cost Clause
PJM	PJM Interconnection, LLC
POLR	Provider of Last Resort
PPA	Power Purchase Agreement
PRPs	Potentially Responsible Parties
REC	Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement Units	Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
Rider	Reconcilable Surcharge Recovery Mechanism
ROE	Return on Equity
ROU	Right-of-use
RTO	Regional Transmission Organization
SEC	United States Securities and Exchange Commission
SOFR	Secured Overnight Financing Rate
SOS	Standard Offer Service
TCJA	Tax Cuts and Jobs Act
ZEC	Zero Emission Credit or Zero Emission Certificate

6

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.

The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the 2023 Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 11, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.

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

WHERE TO FIND MORE INFORMATION

The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and 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.

7

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

8

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)	2024		2023		2024		2023
Operating revenues
Electric operating revenues	$	6,012	$	5,684	$	16,379	$	14,579
Natural gas operating revenues	196		188		1,207		1,268
Revenues from alternative revenue programs	(54)		108		(29)		513
Total operating revenues	6,154		5,980		17,557		16,360
Operating expenses
Purchased power	2,349		2,364		6,483		5,766
Purchased fuel	34		33		301		449
Operating and maintenance	1,275		1,187		3,756		3,535
Depreciation and amortization	908		890		2,681		2,616
Taxes other than income taxes	395		383		1,127		1,063
Total operating expenses	4,961		4,857		14,348		13,429
Gain on sale of assets	3		—		12		—
Operating income	1,196		1,123		3,221		2,931
Other income and (deductions)
Interest expense, net	(490)		(431)		(1,428)		(1,259)
Interest expense to affiliates	(6)		(6)		(18)		(18)
Other, net	57		81		196		331
Total other income and (deductions)	(439)		(356)		(1,250)		(946)
Income before income taxes	757		767		1,971		1,985
Income taxes	50		67		158		274
Net income attributable to common shareholders	$	707	$	700	$	1,813	$	1,711
Comprehensive income, net of income taxes
Net income	$	707	$	700	$	1,813	$	1,711
Other comprehensive (loss) income, net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost	5		16		15		22
Pension and non-pension postretirement benefit plans valuation adjustments	—		(3)		(26)		(16)
Unrealized (loss) gain on cash flow hedges	(29)		21		1		36
Other comprehensive (loss) income	(24)		34		(10)		42
Comprehensive income attributable to common shareholders	$	683	$	734	$	1,803	$	1,753
Average shares of common stock outstanding:
Basic	1,003		996		1,002		996
Assumed exercise and/or distributions of stock-based awards(a)	1		1		—		—
Diluted	1,004		997		1,002		996
Earnings per average common share
Basic	$	0.70	$	0.70	$	1.81	$	1.72
Diluted	$	0.70	$	0.70	$	1.81	$	1.72

__________

(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

9

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
(In millions)	2024		2023
Cash flows from operating activities
Net income	$	1,813	$	1,711
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion	2,683		2,616
Gain on sales of assets	(12)		—
Deferred income taxes and amortization of investment tax credits	102		210
Net fair value changes related to derivatives	1		21
Other non-cash operating activities	441		(237)
Changes in assets and liabilities:
Accounts receivable	(489)		82
Inventories	(57)		(8)
Accounts payable and accrued expenses	(309)		(454)
Collateral received (paid), net	21		(183)
Income taxes	(18)		50
Regulatory assets and liabilities, net	194		(395)
Pension and non-pension postretirement benefit contributions	(140)		(97)
Other assets and liabilities	(87)		(24)
Net cash flows provided by operating activities	4,143		3,292
Cash flows from investing activities
Capital expenditures	(5,161)		(5,540)
Proceeds from sales of assets and businesses	38		—
Other investing activities	9		25
Net cash flows used in investing activities	(5,114)		(5,515)
Cash flows from financing activities
Changes in short-term borrowings	(1,093)		(1,116)
Proceeds from short-term borrowings with maturities greater than 90 days	150		400
Repayments on short-term borrowings with maturities greater than 90 days	(549)		(150)
Issuance of long-term debt	4,975		5,300
Retirement of long-term debt	(1,336)		(1,209)
Issuance of common stock	148		—
Dividends paid on common stock	(1,142)		(1,074)
Proceeds from employee stock plans	33		30
Other financing activities	(83)		(101)
Net cash flows provided by financing activities	1,103		2,080
Increase (decrease) in cash, restricted cash, and cash equivalents	132		(143)
Cash, restricted cash, and cash equivalents at beginning of period	1,101		1,090
Cash, restricted cash, and cash equivalents at end of period	$	1,233	$	947
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	6		(169)
Increase (decrease) in PP&E related to ARO update	16		(4)

See the Combined Notes to Consolidated Financial Statements

10

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
ASSETS
Current assets
Cash and cash equivalents	$	616	$	445
Restricted cash and cash equivalents	552		482
Accounts receivable
Customer accounts receivable	2,971		2,659
Customer allowance for credit losses	(426)		(317)
Customer accounts receivable, net	2,545		2,342
Other accounts receivable	1,226		1,101
Other allowance for credit losses	(111)		(82)
Other accounts receivable, net	1,115		1,019
Inventories, net
Fossil fuel	78		94
Materials and supplies	777		707
Regulatory assets	1,869		2,215
Other	471		473
Total current assets	8,023		7,777
Property, plant, and equipment (net of accumulated depreciation and amortization of $18,227 and $17,251 as of September 30, 2024 and December 31, 2023, respectively)	76,661		73,593
Deferred debits and other assets
Regulatory assets	8,657		8,698
Goodwill	6,630		6,630
Receivable related to Regulatory Agreement Units	4,322		3,232
Investments	279		251
Other	1,498		1,365
Total deferred debits and other assets	21,386		20,176
Total assets	$	106,070	$	101,546

See the Combined Notes to Consolidated Financial Statements

11

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	1,031	$	2,523
Long-term debt due within one year	954		1,403
Accounts payable	2,648		2,846
Accrued expenses	1,284		1,375
Payables to affiliates	5		5
Customer deposits	432		411
Regulatory liabilities	430		389
Mark-to-market derivative liabilities	25		74
Unamortized energy contract liabilities	6		8
Other	569		557
Total current liabilities	7,384		9,591
Long-term debt	43,701		39,692
Long-term debt to financing trusts	390		390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	12,551		11,956
Regulatory liabilities	10,563		9,576
Pension obligations	1,553		1,571
Non-pension postretirement benefit obligations	528		527
Asset retirement obligations	289		267
Mark-to-market derivative liabilities	180		106
Unamortized energy contract liabilities	22		27
Other	2,287		2,088
Total deferred credits and other liabilities	27,973		26,118
Total liabilities	79,448		75,791
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 1,005 shares and 999 shares outstanding as of September 30, 2024 and December 31, 2023, respectively)	21,320		21,114
Treasury stock, at cost (2 shares as of September 30, 2024 and December 31, 2023)	(123)		(123)
Retained earnings	6,161		5,490
Accumulated other comprehensive loss, net	(736)		(726)
Total shareholders’ equity	26,622		25,755
Total liabilities and shareholders’ equity	$	106,070	$	101,546

See the Combined Notes to Consolidated Financial Statements

12

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Nine Months Ended September 30, 2024
(In millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Loss, net		Total Shareholders' Equity
Balance at December 31, 2023	1,001,249	$	21,114	$	(123)	$	5,490	$	(726)	$	25,755
Net income	—	—		—		658		—		658
Long-term incentive plan activity	333	2		—		—		—		2
Employee stock purchase plan issuances	276	13		—		—		—		13
Common stock dividends ($0.38/common share)	—	—		—		(381)				(381)
Other comprehensive income, net of income taxes	—	—		—		—		14		14
Balance at March 31, 2024	1,001,858	$	21,129	$	(123)	$	5,767	$	(712)	$	26,061
Net income	—	—		—		448		—		448
Long-term incentive plan activity	76	11		—		—		—		11
Employee stock purchase plan issuances	396	12		—		—		—		12
Common stock dividends ($0.38/common share)	—	—		—		(380)		—		(380)
Balance at June 30, 2024	1,002,330	$	21,152	$	(123)	$	5,835	$	(712)	$	26,152
Net income	—	—		—		707		—		707
Long-term incentive plan activity	7	7		—		—		—		7
Employee stock purchase plan issuances	349	13		—		—		—		13
Issuance of common stock	3,980	148		—		—		—		148
Common stock dividends ($0.38/common share)	—	—		—		(381)		—		(381)
Other comprehensive income, net of income taxes	—	—		—		—		(24)		(24)
Balance at September 30, 2024	1,006,666	$	21,320	$	(123)	$	6,161	$	(736)	$	26,622

See the Combined Notes to Consolidated Financial Statements

13

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Nine Months Ended September 30, 2023
(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, 2022	995,830	$	20,908	$	(123)	$	4,597	$	(638)	$	24,744
Net income	—	—		—		669		—		669
Long-term incentive plan activity	306	1		—		—		—		1
Employee stock purchase plan issuances	266	12		—		—		—		12
Common stock dividends ($0.36/common share)	—	—		—		(359)		—		(359)
Other comprehensive loss, net of income taxes	—	—		—		—		(1)		(1)
Balance at March 31, 2023	996,402	$	20,921	$	(123)	$	4,907	$	(639)	$	25,066
Net income	—	—		—		343		—		343
Long-term incentive plan activity	372	9		—		—		—		9
Employee stock purchase plan issuances	278	11		—		—		—		11
Common stock dividends ($0.36/common share)	—	—		—		(359)		—		(359)
Other comprehensive income, net of income taxes	—	—		—		—		9		9
Balance at June 30, 2023	997,052	$	20,941	$	(123)	$	4,891	$	(630)	$	25,079
Net Income	—	—		—		700		—		700
Long-term incentive plan activity	(84)	3		—		—		—		3
Employee stock purchase plan issuances	302	12		—		—		—		12
Common stock dividends ($0.36/common share)	—	—		—		(358)		—		(358)
Other comprehensive income, net of income taxes	—	—		—		—		34		34
Balance at September 30, 2023	997,270	$	20,956	$	(123)	$	5,233	$	(596)	$	25,470

See the Combined Notes to Consolidated Financial Statements

14

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)	2024		2023		2024		2023
Operating revenues
Electric operating revenues	$	2,303	$	2,124	$	6,497	$	5,417
Revenues from alternative revenue programs	(76)		135		(100)		405
Operating revenues from affiliates	2		9		6		14
Total operating revenues	2,229		2,268		6,403		5,836
Operating expenses
Purchased power	835		896		2,504		2,068
Operating and maintenance	307		293		970		814
Operating and maintenance from affiliates	103		92		307		263
Depreciation and amortization	387		357		1,124		1,045
Taxes other than income taxes	99		100		287		282
Total operating expenses	1,731		1,738		5,192		4,472
Gain on sale of assets	—		—		5		—
Operating income	498		530		1,216		1,364
Other income and (deductions)
Interest expense, net	(125)		(116)		(364)		(347)
Interest expense to affiliates	(3)		(3)		(10)		(10)
Other, net	26		16		66		50
Total other income and (deductions)	(102)		(103)		(308)		(307)
Income before income taxes	396		427		908		1,057
Income taxes	36		94		85		235
Net income	$	360	$	333	$	823	$	822
Comprehensive income	$	360	$	333	$	823	$	822

See the Combined Notes to Consolidated Financial Statements

15

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
(In millions)	2024		2023
Cash flows from operating activities
Net income	$	823	$	822
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	1,124		1,045
Gain on sales of assets	(5)		—
Deferred income taxes and amortization of investment tax credits	(16)		164
Other non-cash operating activities	161		(392)
Changes in assets and liabilities:
Accounts receivable	(327)		(111)
Receivables from and payables to affiliates, net	43		(12)
Inventories	(17)		(64)
Accounts payable and accrued expenses	(207)		(199)
Collateral received, net	21		28
Income taxes	(109)		50
Regulatory assets and liabilities, net	422		(248)
Pension and non-pension postretirement benefit contributions	(11)		(26)
Other assets and liabilities	134		(72)
Net cash flows provided by operating activities	2,036		985
Cash flows from investing activities
Capital expenditures	(1,619)		(1,926)
Other investing activities	8		8
Net cash flows used in investing activities	(1,611)		(1,918)
Cash flows from financing activities
Changes in short-term borrowings	(129)		(150)
Proceeds from short-term borrowings with maturities greater than 90 days	—		400
Repayments on short-term borrowings with maturities greater than 90 days	(400)		(150)
Issuance of long-term debt	800		975
Retirement of long-term debt	(250)		—
Dividends paid on common stock	(582)		(560)
Contributions from parent	117		570
Other financing activities	(12)		(12)
Net cash flows (used in) provided by financing activities	(456)		1,073
(Decrease) increase in cash, restricted cash, and cash equivalents	(31)		140
Cash, restricted cash, and cash equivalents at beginning of period	686		511
Cash, restricted cash, and cash equivalents at end of period	$	655	$	651
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(31)	$	(27)

See the Combined Notes to Consolidated Financial Statements

16

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
ASSETS
Current assets
Cash and cash equivalents	$	109	$	110
Restricted cash and cash equivalents	481		402
Accounts receivable
Customer accounts receivable	1,116		860
Customer allowance for credit losses	(121)		(69)
Customer accounts receivable, net	995		791
Other accounts receivable	321		242
Other allowance for credit losses	(39)		(17)
Other accounts receivable, net	282		225
Receivables from affiliates	4		3
Inventories, net	294		279
Regulatory assets	1,050		1,335
Other	151		123
Total current assets	3,366		3,268
Property, plant, and equipment (net of accumulated depreciation and amortization of $7,663 and $7,222 as of September 30, 2024 and December 31, 2023, respectively)	29,874		29,088
Deferred debits and other assets
Regulatory assets	2,665		2,794
Goodwill	2,625		2,625
Receivable related to Regulatory Agreement Units	3,983		2,954
Investments	6		6
Prepaid pension asset	1,180		1,217
Other	1,019		875
Total deferred debits and other assets	11,478		10,471
Total assets	$	44,718	$	42,827

See the Combined Notes to Consolidated Financial Statements

17

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	73	$	602
Long-term debt due within one year	—		250
Accounts payable	736		867
Accrued expenses	367		576
Payables to affiliates	116		72
Customer deposits	127		118
Regulatory liabilities	247		191
Mark-to-market derivative liabilities	25		27
Other	260		219
Total current liabilities	1,951		2,922
Long-term debt	12,028		11,236
Long-term debt to financing trust	206		205
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	5,539		5,327
Regulatory liabilities	8,592		7,493
Asset retirement obligations	165		149
Non-pension postretirement benefits obligations	166		161
Mark-to-market derivative liabilities	140		106
Other	1,210		865
Total deferred credits and other liabilities	15,812		14,101
Total liabilities	29,997		28,464
Commitments and contingencies
Shareholders’ equity
Common stock	1,588		1,588
Other paid-in capital	10,518		10,401
Retained earnings	2,615		2,374
Total shareholders’ equity	14,721		14,363
Total liabilities and shareholders’ equity	$	44,718	$	42,827

    

See the Combined Notes to Consolidated Financial Statements

18

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)

	Nine Months Ended September 30, 2024
(In millions)	Common Stock		Other Paid-In Capital		Retained Earnings		Total Shareholders’ Equity
Balance at December 31, 2023	$	1,588	$	10,401	$	2,374	$	14,363
Net income	—		—		193		193
Common stock dividends	—		—		(194)		(194)
Contributions from parent	—		39		—		39
Balance at March 31, 2024	$	1,588	$	10,440	$	2,373	$	14,401
Net income	—		—		270		270
Common stock dividends	—		—		(194)		(194)
Contributions from parent	—		39		—		39
Balance at June 30, 2024	$	1,588	$	10,479	$	2,449	$	14,516
Net income	—		—		360		360
Common stock dividends	—		—		(194)		(194)
Contributions from parent	—		39		—		39
Balance at September 30, 2024	$	1,588	$	10,518	$	2,615	$	14,721
	Nine Months Ended September 30, 2023
(In millions)	Common Stock		Other Paid-In Capital		Retained Earnings		Total Shareholders’ Equity
Balance at December 31, 2022	$	1,588	$	9,746	$	2,030	$	13,364
Net income	—		—		241		241
Common stock dividends	—		—		(187)		(187)
Contributions from parent	—		186		—		186
Balance at March 31, 2023	$	1,588	$	9,932	$	2,084	$	13,604
Net income	—		—		249		249
Common stock dividends	—		—		(187)		(187)
Contributions from parent	—		186		—		186
Balance at June 30, 2023	$	1,588	$	10,118	$	2,146	$	13,852
Net income	—		—		333		333
Common stock dividends	—		—		(185)		(185)
Contributions from parent	—		198		—		198
Balance at September 30, 2023	$	1,588	$	10,316	$	2,294	$	14,198

See the Combined Notes to Consolidated Financial Statements

19

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)	2024		2023		2024		2023
Operating revenues
Electric operating revenues	$	952	$	957	$	2,529	$	2,478
Natural gas operating revenues	69		67		436		492
Revenues from alternative revenue programs	5		11		3		1
Operating revenues from affiliates	4		2		7		6
Total operating revenues	1,030		1,037		2,975		2,977
Operating expenses
Purchased power	372		396		977		994
Purchased fuel	14		15		136		203
Operating and maintenance	251		217		695		622
Operating and maintenance from affiliates	62		60		181		164
Depreciation and amortization	108		100		318		297
Taxes other than income taxes	61		59		164		156
Total operating expenses	868		847		2,471		2,436
Gain on sales of assets	—		—		4		—
Operating income	162		190		508		541
Other income and (deductions)
Interest expense, net	(55)		(51)		(161)		(142)
Interest expense to affiliates	(3)		(1)		(9)		(7)
Other, net	9		11		27		26
Total other income and (deductions)	(49)		(41)		(143)		(123)
Income before income taxes	113		149		365		418
Income taxes	(4)		3		9		8
Net income	$	117	$	146	$	356	$	410
Comprehensive income	$	117	$	146	$	356	$	410

See the Combined Notes to Consolidated Financial Statements

20

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
(In millions)	2024		2023
Cash flows from operating activities
Net income	$	356	$	410
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	318		297
Gain on sales of assets	(4)		—
Deferred income taxes and amortization of investment tax credits	(27)		(44)
Other non-cash operating activities	58		2
Changes in assets and liabilities:
Accounts receivable	(75)		135
Receivables from and payables to affiliates, net	(2)		(2)
Inventories	(2)		35
Accounts payable and accrued expenses	(65)		(132)
Income taxes	(55)		76
Regulatory assets and liabilities, net	17		1
Pension and non-pension postretirement benefit contributions	(3)		(1)
Other assets and liabilities	(19)		—
Net cash flows provided by operating activities	497		777
Cash flows from investing activities
Capital expenditures	(1,125)		(1,068)
Changes in Exelon intercompany money pool	(89)		(51)
Other investing activities	5		1
Net cash flows used in investing activities	(1,209)		(1,118)
Cash flows from financing activities
Changes in short-term borrowings	(165)		(239)
Issuance of long-term debt	575		575
Retirement of long-term debt	—		(50)
Dividends paid on common stock	(300)		(303)
Contributions from parent	595		348
Other financing activities	(7)		(6)
Net cash flows provided by financing activities	698		325
Decrease in cash, restricted cash, and cash equivalents	(14)		(16)
Cash, restricted cash, and cash equivalents at beginning of period	51		68
Cash, restricted cash, and cash equivalents at end of period	$	37	$	52
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	60	$	(22)

See the Combined Notes to Consolidated Financial Statements

21

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
ASSETS
Current assets
Cash and cash equivalents	$	28	$	42
Restricted cash and cash equivalents	9		9
Accounts receivable
Customer accounts receivable	546		527
Customer allowance for credit losses	(135)		(95)
Customer accounts receivable, net	411		432
Other accounts receivable	160		117
Other allowance for credit losses	(20)		(8)
Other accounts receivable, net	140		109
Receivables from affiliates	1		2
Receivable from Exelon intercompany money pool	89		—
Inventories, net
Fossil fuel	39		50
Materials and supplies	79		67
Prepaid utility taxes	37		2
Regulatory assets	86		127
Other	63		63
Total current assets	982		903
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,003 and $4,097 as of September 30, 2024 and December 31, 2023, respectively)	14,021		13,128
Deferred debits and other assets
Regulatory assets	903		793
Receivable related to Regulatory Agreement Units	338		278
Investments	39		35
Prepaid pension asset	434		429
Other	31		29
Total deferred debits and other assets	1,745		1,564
Total assets	$	16,748	$	15,595

See the Combined Notes to Consolidated Financial Statements

22

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	165
Accounts payable	556		512
Accrued expenses	148		236
Payables to affiliates	36		39
Customer deposits	76		79
Regulatory liabilities	83		92
Other	64		59
Total current liabilities	963		1,182
Long-term debt	5,703		5,134
Long-term debt to financing trusts	184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,389		2,321
Regulatory liabilities	376		314
Asset retirement obligations	28		26
Non-pension postretirement benefits obligations	287		286
Other	98		79
Total deferred credits and other liabilities	3,178		3,026
Total liabilities	10,028		9,526
Commitments and contingencies
Shareholder’s equity
Common stock	4,645		4,050
Retained earnings	2,075		2,019
Total shareholder’s equity	6,720		6,069
Total liabilities and shareholder's equity	$	16,748	$	15,595

See the Combined Notes to Consolidated Financial Statements

23

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)

	Nine Months Ended September 30, 2024
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2023	$	4,050	$	2,019	$	6,069
Net income	—		149		149
Common stock dividends	—		(100)		(100)
Contributions from parent	580		—		580
Balance at March 31, 2024	$	4,630	$	2,068	$	6,698
Net income	—		90		90
Common stock dividends	—		(100)		(100)
Balance at June 30, 2024	$	4,630	$	2,058	$	6,688
Net income	—		117		117
Common stock dividends	—		(100)		(100)
Contributions from parent	15		—		15
Balance at September 30, 2024	$	4,645	$	2,075	$	6,720
	Nine Months Ended September 30, 2023
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2022	$	3,702	$	1,861	$	5,563
Net income	—		166		166
Common stock dividends	—		(101)		(101)
Contributions from parent	330		—		330
Balance at March 31, 2023	$	4,032	$	1,926	$	5,958
Net income	—		97		97
Common stock dividends	—		(101)		(101)
Balance at June 30, 2023	$	4,032	$	1,922	$	5,954
Net income	—		146		146
Common stock dividends	—		(101)		(101)
Contributions from parent	18		—		18
Balance at September 30, 2023	$	4,050	$	1,967	$	6,017

See the Combined Notes to Consolidated Financial Statements

24

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2024		2023		2024		2023
Operating revenues
Electric operating revenues	$	928	$	856	$	2,585	$	2,306
Natural gas operating revenues	104		96		648		627
Revenues from alternative revenue programs	9		(22)		28		47
Operating revenues from affiliates	3		2		7		6
Total operating revenues	1,044		932		3,268		2,986
Operating expenses
Purchased power	407		371		1,108		975
Purchased fuel	13		9		120		170
Operating and maintenance	221		156		613		467
Operating and maintenance from affiliates	60		58		182		165
Depreciation and amortization	162		161		474		487
Taxes other than income taxes	86		80		254		239
Total operating expenses	949		835		2,751		2,503
Operating income	95		97		517		483
Other income and (deductions)
Interest expense, net	(57)		(47)		(159)		(135)
Other, net	11		6		27		14
Total other income and (deductions)	(46)		(41)		(132)		(121)
Income before income taxes	49		56		385		362
Income taxes	4		11		32		76
Net income	$	45	$	45	$	353	$	286
Comprehensive income	$	45	$	45	$	353	$	286

See the Combined Notes to Consolidated Financial Statements

25

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
(In millions)	2024		2023
Cash flows from operating activities
Net income	$	353	$	286
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	474		487
Deferred income taxes and amortization of investment tax credits	(5)		41
Other non-cash operating activities	49		—
Changes in assets and liabilities:
Accounts receivable	25		194
Receivables from and payables to affiliates, net	14		(7)
Inventories	(6)		45
Accounts payable and accrued expenses	37		(38)
Collateral paid, net	—		(22)
Income taxes	(51)		19
Regulatory assets and liabilities, net	(69)		(151)
Pension and non-pension postretirement benefit contributions	(34)		(15)
Other assets and liabilities	102		46
Net cash flows provided by operating activities	889		885
Cash flows from investing activities
Capital expenditures	(1,033)		(986)
Other investing activities	10		6
Net cash flows used in investing activities	(1,023)		(980)
Cash flows from financing activities
Changes in short-term borrowings	(336)		(349)
Issuance of long-term debt	800		700
Retirement of long-term debt	—		(300)
Dividends paid on common stock	(276)		(237)
Contributions from parent	237		237
Other financing activities	(9)		(7)
Net cash flows provided by financing activities	416		44
Increase (decrease) in cash, restricted cash, and cash equivalents	282		(51)
Cash, restricted cash, and cash equivalents at beginning of period	48		67
Cash, restricted cash, and cash equivalents at end of period	$	330	$	16
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	38	$	(17)

See the Combined Notes to Consolidated Financial Statements

26

BALTIMORE GAS AND ELECTRIC COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
ASSETS
Current assets
Cash and cash equivalents	$	330	$	47
Restricted cash and cash equivalents	—		1
Accounts receivable
Customer accounts receivable	504		527
Customer allowance for credit losses	(60)		(46)
Customer accounts receivable, net	444		481
Other accounts receivable	100		106
Other allowance for credit losses	(6)		(7)
Other accounts receivable, net	94		99
Inventories, net
Fossil fuel	31		35
Materials and supplies	83		74
Prepaid utility taxes	3		56
Regulatory assets	217		229
Other	20		25
Total current assets	1,222		1,047
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,933 and $4,744 as of September 30, 2024 and December 31, 2023, respectively)	12,765		12,102
Deferred debits and other assets
Regulatory assets	764		727
Investments	10		9
Prepaid pension asset	230		248
Other	47		51
Total deferred debits and other assets	1,051		1,035
Total assets	$	15,038	$	14,184

See the Combined Notes to Consolidated Financial Statements

27

BALTIMORE GAS AND ELECTRIC COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	336
Accounts payable	398		344
Accrued expenses	176		203
Payables to affiliates	48		35
Customer deposits	118		114
Regulatory liabilities	17		27
Other	78		34
Total current liabilities	835		1,093
Long-term debt	5,395		4,602
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,041		1,945
Regulatory liabilities	681		773
Asset retirement obligations	36		32
Non-pension postretirement benefits obligations	151		158
Other	95		91
Total deferred credits and other liabilities	3,004		2,999
Total liabilities	9,234		8,694
Commitments and contingencies
Shareholder's equity
Common stock	3,483		3,246
Retained earnings	2,321		2,244
Total shareholder's equity	5,804		5,490
Total liabilities and shareholder's equity	$	15,038	$	14,184

See the Combined Notes to Consolidated Financial Statements

28

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

	Nine Months Ended September 30, 2024
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2023	$	3,246	$	2,244	$	5,490
Net income	—		264		264
Common stock dividends	—		(92)		(92)
Balance at March 31, 2024	$	3,246	$	2,416	$	5,662
Net income	—		44		44
Common stock dividends	—		(92)		(92)
Contributions from parent	197		—		197
Balance at June 30, 2024	$	3,443	$	2,368	$	5,811
Net income	—		45		45
Common stock dividends	—		(92)		(92)
Contributions from parent	40		—		40
Balance at September 30, 2024	$	3,483	$	2,321	$	5,804
	Nine Months Ended September 30, 2023
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2022	$	2,861	$	2,075	$	4,936
Net income	—		200		200
Common stock dividends	—		(80)		(80)
Contributions from parent	237		—		237
Balance at March 31, 2023	$	3,098	$	2,195	$	5,293
Net income	—		42		42
Common stock dividends	—		(79)		(79)
Balance at June 30, 2023	$	3,098	$	2,158	$	5,256
Net income	—		45		45
Common stock dividends	—		(79)		(79)
Balance at September 30, 2023	$	3,098	$	2,124	$	5,222

See the Combined Notes to Consolidated Financial Statements

29

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)	2024		2023		2024		2023
Operating revenues
Electric operating revenues	$	1,828	$	1,762	$	4,769	$	4,399
Natural gas operating revenues	23		24		122		150
Revenues from alternative revenue programs	8		(15)		40		59
Operating revenues from affiliates	3		2		7		7
Total operating revenues	1,862		1,773		4,938		4,615
Operating expenses
Purchased power	735		701		1,895		1,729
Purchased fuel	7		9		44		76
Operating and maintenance	275		288		780		815
Operating and maintenance from affiliates	47		51		147		137
Depreciation and amortization	235		257		716		741
Taxes other than income taxes	140		134		395		366
Total operating expenses	1,439		1,440		3,977		3,864
Operating income	423		333		961		751
Other income and (deductions)
Interest expense, net	(95)		(80)		(279)		(238)
Other, net	22		28		79		80
Total other income and (deductions)	(73)		(52)		(200)		(158)
Income before income taxes	350		281		761		593
Income taxes	72		49		158		103
Net income	$	278	$	232	$	603	$	490
Comprehensive income	$	278	$	232	$	603	$	490

See the Combined Notes to Consolidated Financial Statements

30

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
(In millions)	2024		2023
Cash flows from operating activities
Net income	$	603	$	490
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	716		741
Deferred income taxes and amortization of investment tax credits	56		44
Other non-cash operating activities	96		80
Changes in assets and liabilities:
Accounts receivable	(116)		(160)
Receivables from and payables to affiliates, net	(8)		(8)
Inventories	(32)		(22)
Accounts payable and accrued expenses	37		23
Collateral received (paid), net	1		(191)
Income taxes	(55)		37
Regulatory assets and liabilities, net	(158)		(2)
Pension and non-pension postretirement benefit contributions	(79)		(15)
Other assets and liabilities	(74)		(98)
Net cash flows provided by operating activities	987		919
Cash flows from investing activities
Capital expenditures	(1,343)		(1,510)
Other investing activities	—		8
Net cash flows used in investing activities	(1,343)		(1,502)
Cash flows from financing activities
Changes in short-term borrowings	(176)		(241)
Issuance of long-term debt	1,100		550
Retirement of long-term debt	(583)		—
Changes in Exelon intercompany money pool	10		18
Distributions to member	(549)		(410)
Contributions from member	505		475
Other financing activities	(33)		(36)
Net cash flows provided by financing activities	274		356
Decrease in cash, restricted cash, and cash equivalents	(82)		(227)
Cash, restricted cash, and cash equivalents at beginning of period	204		373
Cash, restricted cash, and cash equivalents at end of period	$	122	$	146
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(27)	$	(96)

See the Combined Notes to Consolidated Financial Statements

31

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
ASSETS
Current assets
Cash and cash equivalents	$	100	$	180
Restricted cash and cash equivalents	22		24
Accounts receivable
Customer accounts receivable	806		745
Customer allowance for credit losses	(110)		(107)
Customer accounts receivable, net	696		638
Other accounts receivable	321		310
Other allowance for credit losses	(46)		(50)
Other accounts receivable, net	275		260
Receivables from affiliates	6		3
Inventories, net
Fossil fuel	7		9
Materials and supplies	320		287
Regulatory assets	326		337
Other	70		100
Total current assets	1,822		1,838
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,574 and $3,175 as of September 30, 2024 and December 31, 2023, respectively)	19,632		18,851
Deferred debits and other assets
Regulatory assets	1,597		1,587
Goodwill	4,005		4,005
Investments	151		143
Prepaid pension asset	272		268
Other	193		211
Total deferred debits and other assets	6,218		6,214
Total assets	$	27,672	$	26,903

See the Combined Notes to Consolidated Financial Statements

32

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings	$	218	$	394
Long-term debt due within one year	140		644
Accounts payable	635		683
Accrued expenses	330		338
Payables to affiliates	54		59
Borrowings from Exelon intercompany money pool	75		65
Customer deposits	111		100
Regulatory liabilities	73		71
Unamortized energy contract liabilities	6		8
PPA termination obligation	10		49
Other	102		138
Total current liabilities	1,754		2,549
Long-term debt	8,995		8,004
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	3,157		3,031
Regulatory liabilities	828		904
Asset retirement obligations	56		55
Non-pension postretirement benefit obligations	36		40
Unamortized energy contract liabilities	23		27
Other	481		511
Total deferred credits and other liabilities	4,581		4,568
Total liabilities	15,330		15,121
Commitments and contingencies
Member's equity
Membership interest	12,562		12,057
Undistributed losses	(220)		(275)
Total member's equity	12,342		11,782
Total liabilities and member's equity	$	27,672	$	26,903

See the Combined Notes to Consolidated Financial Statements

33

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY

(Unaudited)

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

	Nine Months Ended September 30, 2023
(In millions)	Membership Interest		Undistributed (Losses)/Gains		Total Member's Equity
Balance at December 31, 2022	$	11,582	$	(352)	$	11,230
Net income	—		155		155
Distributions to member	—		(112)		(112)
Contributions from member	405		—		405
Balance at March 31, 2023	$	11,987	$	(309)	$	11,678
Net income	—		103		103
Distributions to member	—		(100)		(100)
Balance at June 30, 2023	$	11,987	$	(306)	$	11,681
Net income	—		232		232
Distributions to member	—		(198)		(198)
Contributions from member	70		—		70
Balance at September 30, 2023	$	12,057	$	(272)	$	11,785

See the Combined Notes to Consolidated Financial Statements

34

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2024		2023		2024		2023
Operating revenues
Electric operating revenues	$	854	$	839	$	2,273	$	2,141
Revenues from alternative revenue programs	5		(18)		42		28
Operating revenues from affiliates	2		1		5		5
Total operating revenues	861		822		2,320		2,174
Operating expenses
Purchased power	294		288		808		750
Operating and maintenance	82		89		206		264
Operating and maintenance from affiliates	58		60		186		176
Depreciation and amortization	102		112		307		329
Taxes other than income taxes	114		109		317		291
Total operating expenses	650		658		1,824		1,810
Operating income	211		164		496		364
Other income and (deductions)
Interest expense, net	(50)		(41)		(142)		(122)
Other, net	11		18		43		50
Total other income and (deductions)	(39)		(23)		(99)		(72)
Income before income taxes	172		141		397		292
Income taxes	32		21		74		43
Net income	$	140	$	120	$	323	$	249
Comprehensive income	$	140	$	120	$	323	$	249

See the Combined Notes to Consolidated Financial Statements

35

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
(In millions)	2024		2023
Cash flows from operating activities
Net income	$	323	$	249
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	307		329
Deferred income taxes and amortization of investment tax credits	22		22
Other non-cash operating activities	(11)		38
Changes in assets and liabilities:
Accounts receivable	(37)		(84)
Receivables from and payables to affiliates, net	1		(2)
Inventories	(10)		(12)
Accounts payable and accrued expenses	61		33
Collateral paid, net	(1)		(26)
Income taxes	(45)		15
Regulatory assets and liabilities, net	(54)		(7)
Pension and non-pension postretirement benefit contributions	(7)		(9)
Other assets and liabilities	(56)		(13)
Net cash flows provided by operating activities	493		533
Cash flows from investing activities
Capital expenditures	(672)		(710)
Changes in PHI intercompany money pool	—		(7)
Other investing activities	—		8
Net cash flows used in investing activities	(672)		(709)
Cash flows from financing activities
Changes in short-term borrowings	(83)		(299)
Issuance of long-term debt	675		350
Retirement of long-term debt	(400)		—
Dividends paid on common stock	(286)		(200)
Contributions from parent	260		308
Other financing activities	(19)		(26)
Net cash flows provided by financing activities	147		133
Decrease in cash, restricted cash, and cash equivalents	(32)		(43)
Cash, restricted cash, and cash equivalents at beginning of period	72		99
Cash, restricted cash, and cash equivalents at end of period	$	40	$	56
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(27)	$	(39)

See the Combined Notes to Consolidated Financial Statements

36

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
ASSETS
Current assets
Cash and cash equivalents	$	20	$	48
Restricted cash and cash equivalents	20		24
Accounts receivable
Customer accounts receivable	385		369
Customer allowance for credit losses	(58)		(52)
Customer accounts receivable, net	327		317
Other accounts receivable	166		166
Other allowance for credit losses	(26)		(28)
Other accounts receivable, net	140		138
Receivables from affiliates	—		2
Inventories, net	169		159
Regulatory assets	157		150
Other	18		51
Total current assets	851		889
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,457 and $4,284 as of September 30, 2024 and December 31, 2023, respectively)	9,863		9,430
Deferred debits and other assets
Regulatory assets	472		450
Investments	133		124
Prepaid pension asset	228		246
Other	55		55
Total deferred debits and other assets	888		875
Total assets	$	11,602	$	11,194

See the Combined Notes to Consolidated Financial Statements

37

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	49	$	132
Long-term debt due within one year	6		405
Accounts payable	304		321
Accrued expenses	182		191
Payables to affiliates	31		32
Customer deposits	54		47
Regulatory liabilities	17		15
Merger related obligation	22		25
Other	33		61
Total current liabilities	698		1,229
Long-term debt	4,356		3,691
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,500		1,431
Regulatory liabilities	334		382
Asset retirement obligations	38		37
Other	235		280
Total deferred credits and other liabilities	2,107		2,130
Total liabilities	7,161		7,050
Commitments and contingencies
Shareholder's equity
Common stock	3,335		3,075
Retained earnings	1,106		1,069
Total shareholder's equity	4,441		4,144
Total liabilities and shareholder's equity	$	11,602	$	11,194

See the Combined Notes to Consolidated Financial Statements

38

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

	Nine Months Ended September 30, 2024
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2023	$	3,075	$	1,069	$	4,144
Net income	—		75		75
Common stock dividends	—		(51)		(51)
Contributions from parent	251		—		251
Balance at March 31, 2024	$	3,326	$	1,093	$	4,419
Net income	—		108		108
Common stock dividends	—		(102)		(102)
Balance at June 30, 2024	$	3,326	$	1,099	$	4,425
Net income	—		140		140
Common stock dividends	—		(133)		(133)
Contributions from parent	9		—		9
Balance at September 30, 2024	$	3,335	$	1,106	$	4,441

	Nine Months Ended September 30, 2023
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2022	$	2,767	$	1,015	$	3,782
Net income	—		65		65
Common stock dividends	—		(48)		(48)
Contributions from parent	243		—		243
Balance at March 31, 2023	$	3,010	$	1,032	$	4,042
Net income	—		64		64
Common stock dividends	—		(67)		(67)
Balance at June 30, 2023	$	3,010	$	1,029	$	4,039
Net income	—		120		120
Common stock dividends	—		(85)		(85)
Contributions from parent	65		—		65
Balance at September 30, 2023	$	3,075	$	1,064	$	4,139

See the Combined Notes to Consolidated Financial Statements

39

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2024		2023		2024		2023
Operating revenues
Electric operating revenues	$	440	$	426	$	1,215	$	1,108
Natural gas operating revenues	23		24		122		150
Revenues from alternative revenue programs	(3)		(2)		1		10
Operating revenues from affiliates	2		2		5		5
Total operating revenues	462		450		1,343		1,273
Operating expenses
Purchased power	196		192		529		486
Purchased fuel	7		9		44		76
Operating and maintenance	49		60		151		150
Operating and maintenance from affiliates	43		44		133		128
Depreciation and amortization	62		62		183		182
Taxes other than income taxes	20		19		59		57
Total operating expenses	377		386		1,099		1,079
Operating income	85		64		244		194
Other income and (deductions)
Interest expense, net	(22)		(18)		(69)		(53)
Other, net	6		5		20		12
Total other income and (deductions)	(16)		(13)		(49)		(41)
Income before income taxes	69		51		195		153
Income taxes	14		8		39		25
Net income	$	55	$	43	$	156	$	128
Comprehensive income	$	55	$	43	$	156	$	128

See the Combined Notes to Consolidated Financial Statements

40

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
(In millions)	2024		2023
Cash flows from operating activities
Net income	$	156	$	128
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	183		182
Deferred income taxes and amortization of investment tax credits	12		4
Other non-cash operating activities	29		11
Changes in assets and liabilities:
Accounts receivable	(1)		9
Receivables from and payables to affiliates, net	(3)		3
Inventories	(17)		2
Accounts payable and accrued expenses	14		(1)
Collateral received (paid), net	2		(120)
Income taxes	(25)		15
Regulatory assets and liabilities, net	(41)		33
Pension and non-pension postretirement benefit contributions	(1)		—
Other assets and liabilities	19		8
Net cash flows provided by operating activities	327		274
Cash flows from investing activities
Capital expenditures	(404)		(416)
Changes in PHI intercompany money pool	—		(10)
Net cash flows used in investing activities	(404)		(426)
Cash flows from financing activities
Changes in short-term borrowings	(63)		(115)
Issuance of long-term debt	175		125
Retirement of long-term debt	(33)		—
Dividends paid on common stock	(162)		(97)
Contributions from parent	160		99
Other financing activities	(6)		(6)
Net cash flows provided by financing activities	71		6
Decrease in cash, restricted cash, and cash equivalents	(6)		(146)
Cash, restricted cash, and cash equivalents at beginning of period	16		152
Cash, restricted cash, and cash equivalents at end of period	$	10	$	6
Supplemental cash flow information
Increase in capital expenditures not paid	$	9	$	—

    

See the Combined Notes to Consolidated Financial Statements

41

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
ASSETS
Current assets
Cash and cash equivalents	$	8	$	16
Restricted cash and cash equivalents	2		—
Accounts receivable
Customer accounts receivable	169		183
Customer allowance for credit losses	(17)		(19)
Customer accounts receivable, net	152		164
Other accounts receivable	60		52
Other allowance for credit losses	(7)		(8)
Other accounts receivable, net	53		44
Receivables from affiliates	—		1
Inventories, net
Fossil fuel	7		9
Materials and supplies	91		72
Prepaid utility taxes	20		24
Regulatory assets	60		54
Other	11		14
Total current assets	404		398
Property, plant, and equipment (net of accumulated depreciation and amortization of $2,032 and $1,925 as of September 30, 2024 and December 31, 2023, respectively)	5,415		5,165
Deferred debits and other assets
Regulatory assets	215		218
Prepaid pension asset	124		135
Other	46		50
Total deferred debits and other assets	385		403
Total assets	$	6,204	$	5,966

See the Combined Notes to Consolidated Financial Statements

42

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	63
Long-term debt due within one year	130		84
Accounts payable	161		159
Accrued expenses	63		64
Payables to affiliates	21		25
Customer deposits	34		31
Regulatory liabilities	47		50
Other	20		21
Total current liabilities	476		497
Long-term debt	2,091		1,996
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	935		904
Regulatory liabilities	331		365
Asset retirement obligations	13		12
Non-pension postretirement benefits obligations	5		6
Other	107		93
Total deferred credits and other liabilities	1,391		1,380
Total liabilities	3,958		3,873
Commitments and contingencies
Shareholder's equity
Common stock	1,615		1,455
Retained earnings	631		638
Total shareholder's equity	2,246		2,093
Total liabilities and shareholder's equity	$	6,204	$	5,966

See the Combined Notes to Consolidated Financial Statements

43

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

	Nine Months Ended September 30, 2024
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2023	$	1,455	$	638	$	2,093
Net income	—		66		66
Common stock dividends	—		(45)		(45)
Contributions from parent	154		—		154
Balance at March 31, 2024	$	1,609	$	659	$	2,268
Net income	—		34		34
Common stock dividends	—		(39)		(39)
Balance at June 30, 2024	$	1,609	$	654	$	2,263
Net income	—		55		55
Common stock dividends	—		(78)		(78)
Contributions from parent	6		—		6
Balance at September 30, 2024	$	1,615	$	631	$	2,246

	Nine Months Ended September 30, 2023
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2022	$	1,356	$	594	$	1,950
Net income	—		60		60
Common stock dividends	—		(42)		(42)
Contributions from parent	99		—		99
Balance at March 31, 2023	$	1,455	$	612	$	2,067
Net income	—		25		25
Common stock dividends	—		(18)		(18)
Balance at June 30, 2023	$	1,455	$	619	$	2,074
Net income	—		43		43
Common stock dividends	—		(37)		(37)
Balance, September 30, 2023	$	1,455	$	625	$	2,080

See the Combined Notes to Consolidated Financial Statements

44

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)	2024		2023		2024		2023
Operating revenues
Electric operating revenues	$	533	$	497	$	1,281	$	1,150
Revenues from alternative revenue programs	6		5		(3)		21
Operating revenues from affiliates	1		—		2		1
Total operating revenues	540		502		1,280		1,172
Operating expenses
Purchased power	245		221		557		493
Operating and maintenance	58		56		155		147
Operating and maintenance from affiliates	38		38		119		112
Depreciation and amortization	67		77		214		212
Taxes other than income taxes	2		2		7		7
Total operating expenses	410		394		1,052		971
Operating income	130		108		228		201
Other income and (deductions)
Interest expense, net	(21)		(19)		(59)		(52)
Other, net	4		5		12		13
Total other income and (deductions)	(17)		(14)		(47)		(39)
Income before income taxes	113		94		181		162
Income taxes	30		23		48		40
Net income	$	83	$	71	$	133	$	122
Comprehensive income	$	83	$	71	$	133	$	122

See the Combined Notes to Consolidated Financial Statements

45

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
(In millions)	2024		2023
Cash flows from operating activities
Net income	$	133	$	122
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	214		212
Deferred income taxes and amortization of investment tax credits	33		24
Other non-cash operating activities	49		(2)
Changes in assets and liabilities:
Accounts receivable	(77)		(85)
Receivables from and payables to affiliates, net	(8)		(6)
Inventories	(5)		(11)
Accounts payable and accrued expenses	(18)		(4)
Collateral paid, net	—		(45)
Income taxes	(2)		6
Regulatory assets and liabilities, net	(62)		(28)
Pension and non-pension postretirement benefit contributions	(7)		(1)
Other assets and liabilities	(39)		(80)
Net cash flows provided by operating activities	211		102
Cash flows from investing activities
Capital expenditures	(265)		(376)
Net cash flows used in investing activities	(265)		(376)
Cash flows from financing activities
Changes in short-term borrowings	(30)		173
Issuance of long-term debt	250		75
Retirement of long-term debt	(150)		—
Changes in PHI intercompany money pool	—		17
Dividends paid on common stock	(100)		(111)
Contributions from parent	85		65
Other financing activities	(5)		(3)
Net cash flows provided by financing activities	50		216
Decrease in cash and cash equivalents	(4)		(58)
Cash and cash equivalents at beginning of period	21		72
Cash and cash equivalents at end of period	$	17	$	14
Supplemental cash flow information
Decrease in capital expenditures not paid	$	(10)	$	(56)

See the Combined Notes to Consolidated Financial Statements

46

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
ASSETS
Current assets
Cash and cash equivalents	$	17	$	21
Accounts receivable
Customer accounts receivable	252		194
Customer allowance for credit losses	(35)		(36)
Customer accounts receivable, net	217		158
Other accounts receivable	98		92
Other allowance for credit losses	(13)		(14)
Other accounts receivable, net	85		78
Receivables from affiliates	5		3
Inventories, net	60		55
Prepaid utility taxes	9		—
Regulatory assets	102		125
Other	7		5
Total current assets	502		445
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,763 and $1,684 as of September 30, 2024 and December 31, 2023, respectively)	4,300		4,192
Deferred debits and other assets
Regulatory assets	496		483
Prepaid pension asset	—		3
Other	31		34
Total deferred debits and other assets	527		520
Total assets	$	5,329	$	5,157

See the Combined Notes to Consolidated Financial Statements

47

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions)	September 30, 2024		December 31, 2023
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	169	$	199
Long-term debt due within one year	4		154
Accounts payable	162		192
Accrued expenses	42		42
Payables to affiliates	19		25
Customer deposits	23		23
Regulatory liabilities	8		6
PPA termination obligation	10		49
Other	9		12
Total current liabilities	446		702
Long-term debt	1,931		1,679
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	809		771
Regulatory liabilities	148		140
Non-pension postretirement benefit obligations	2		4
Other	63		49
Total deferred credits and other liabilities	1,022		964
Total liabilities	3,399		3,345
Commitments and contingencies
Shareholder's equity
Common stock	1,915		1,830
Retained earnings (deficit)	15		(18)
Total shareholder's equity	1,930		1,812
Total liabilities and shareholder's equity	$	5,329	$	5,157

See the Combined Notes to Consolidated Financial Statements

48

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)

	Nine Months Ended September 30, 2024
(In millions)	Common Stock		Retained (Deficit) Earnings		Total Shareholder's Equity
Balance at December 31, 2023	$	1,830	$	(18)	$	1,812
Net income	—		29		29
Common stock dividends	—		(22)		(22)
Contributions from parent	81		—		81
Balance at March 31, 2024	$	1,911	$	(11)	$	1,900
Net income	—		21		21
Common stock dividends	—		(22)		(22)
Balance at June 30, 2024	$	1,911	$	(12)	$	1,899
Net income	—		83		83
Common stock dividends	—		(56)		(56)
Contributions from parent	4		—		4
Balance at September 30, 2024	$	1,915	$	15	$	1,930

	Nine Months Ended September 30, 2023
(In millions)	Common Stock		Retained (Deficit) Earnings		Total Shareholder's Equity
Balance at December 31, 2022	$	1,765	$	(12)	$	1,753
Net income	—		33		33
Common stock dividends	—		(21)		(21)
Contributions from parent	63		—		63
Balance at March 31, 2023	$	1,828	$	—	$	1,828
Net income	—		18		18
Common stock dividends	—		(15)		(15)
Balance at June 30, 2023	$	1,828	$	3	$	1,831
Net income	—		71		71
Common stock dividends	—		(75)		(75)
Contributions from parent	2		—		2
Balance, September 30, 2023	$	1,830	$	(1)	$	1,829

See the Combined Notes to Consolidated Financial Statements

49

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 — Significant Accounting Policies

1. Significant Accounting Policies (All Registrants)

Description of Business

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

Name of Registrant	Business	Service Territories
Commonwealth Edison Company	Purchase and regulated retail sale of electricity	Northern Illinois, including the City of Chicago
	Transmission and distribution of electricity to retail customers
PECO Energy Company	Purchase and regulated retail sale of electricity and natural gas	Southeastern Pennsylvania, including the City of Philadelphia (electricity)
	Transmission and distribution of electricity and distribution of natural gas to retail customers	Pennsylvania counties surrounding the City of Philadelphia (natural gas)
Baltimore Gas and Electric Company	Purchase and regulated retail sale of electricity and natural gas	Central Maryland, including the City of Baltimore (electricity and natural gas)
	Transmission and distribution of electricity and distribution of natural gas to retail customers
Pepco Holdings LLC	Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE	Service Territories of Pepco, DPL, and ACE
Potomac Electric  Power Company	Purchase and regulated retail sale of electricity	District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland
	Transmission and distribution of electricity to retail customers
Delmarva Power & Light Company	Purchase and regulated retail sale of electricity and natural gas	Portions of Delaware and Maryland (electricity)
	Transmission and distribution of electricity and distribution of natural gas to retail customers	Portions of New Castle County, Delaware (natural gas)
Atlantic City Electric Company	Purchase and regulated retail sale of electricity	Portions of Southern New Jersey
	Transmission and distribution of electricity to retail customers

Basis of Presentation

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

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

The accompanying consolidated financial statements as of September 30, 2024 and for the three and nine months ended September 30, 2024 and 2023 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, 2023 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, 2024. 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

50

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 — Significant Accounting Policies

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, 2024: 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, 2024. 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.

Segment Reporting (Issued November 2023). Improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The objective of the revised guidance is to introduce a new requirement to disclose significant segment expenses regularly provided to the CODM, extend certain annual disclosures to interim periods, clarify single reportable segment entities must apply ASC 280 in its entirety, permit more than one measure of segment profit or loss to be reported under certain conditions, and require disclosure of the title and position of the CODM. The standard is effective for annual periods beginning January 1, 2024 and interim periods beginning January 1, 2025, with early adoption permitted. The standard will be applied retrospectively.

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

2. Regulatory Matters (All Registrants)

As discussed in Note 3 — Regulatory Matters of the 2023 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2024 and updates to the 2023 Form 10-K.

51

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 2024.

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	$	501	8.905%	December 14, 2023(a)	January 1, 2024
			$	838	$	810	8.905%	April 18, 2024(b)	May 1, 2024
	April 21, 2023(c)	Electric	$	247	$	259	8.91%	November 30, 2023	January 1, 2024
BGE - Maryland(d)	February 17, 2023	Electric	$	313	$	179	9.50%	December 14, 2023	January 1, 2024
		Natural Gas	$	289	$	229	9.45%
Pepco - Maryland(e)	May 16, 2023 (amended February 23, 2024)	Electric	$	111	$	45	9.50%	June 10, 2024	April 1, 2024
DPL - Maryland(f)	May 19, 2022	Electric	$	38	$	29	9.60%	December 14, 2022	January 1, 2023
DPL - Delaware(g)	December 15, 2022 (amended September 29, 2023)	Electric	$	39	$	28	9.60%	April 18, 2024	July 15, 2023
ACE - New Jersey(h)	February 15, 2023 (amended August 21, 2023)	Electric	$	92	$	45	9.60%	November 17, 2023	December 1, 2023

__________

(a)Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $451 million effective January 1, 2024, $14 million effective January 1, 2025, $6 million effective January 1, 2026, and $30 million effective January 1, 2027, based on an ROE of 8.905%, an equity ratio of 50%, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directed that a rehearing process extending no more than 150 days reconsider certain components of the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905% ROE and 50% equity ratio and denial of any return on ComEd’s pension asset. On March 13, 2024, ComEd filed its revised Grid Plan (Refiled Grid Plan) with supporting testimony and schedules with the ICC. On March 15, 2024, ComEd filed a petition to adjust its MRP to authorize increased rates consistent with the Refiled Grid Plan.

(b)Reflects four-year cumulative increase to the revenue requirement approved on December 14, 2023 and amended on January 10, 2024 of $810 million for January 1, 2024 to December 31, 2027 resulting from the rehearing on certain components of the rate plan. On February 16, 2024, ComEd filed a revised revenue request for an $838 million increase in its 2024-2027 revenue requirements based on the ICC’s limited scope for rehearing which included the value of the 2023 forecasted year-end rate base. On April 18, 2024, the ICC issued an order on the rehearing filing which increased the revenue requirements previously approved by the ICC in its January 10, 2024, amendatory order by $150 million in 2024, $186 million in 2025, $221 million in 2026, and $253 million in 2027. ComEd anticipates that the revenue requirements determined during the rehearing process will be further adjusted upon approval of the Refiled Grid Plan and the pending petition to adjust rates.

(c)On November 30, 2023, the Delivery Reconciliation Amount for 2022 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. The delivery reconciliation amount allows for the reconciliation of the revenue

52

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd’s approved MRP. The 2023 filing reconciled the delivery service rates in effect in 2022 with the actual delivery service costs incurred in 2022. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 6.48%, inclusive of an allowed ROE of 8.91%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points.

(d)Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $41 million, $113 million, and $25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $126 million, $62 million, and $41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders between March 2024 through February 2025. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $13 million and $7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $39 million and $15 million for electric and gas, respectively. In April 2024, BGE filed with the MDPSC its request for recovery of the 2023 reconciliation amounts of $79 million and $73 million for electric and gas, respectively, with supporting testimony and schedules.

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

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

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

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

53

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
ComEd - Illinois	March 15, 2024 (amended August 13, 2024)	Electric(a)	$	667	8.905%	December 2024
	April 26, 2024 (amended September 11, 2024)	Electric(b)	$	624	9.89%	Fourth quarter of 2024
PECO - Pennsylvania	March 28, 2024	Electric(c)(d)	$	464	10.95%	Fourth quarter of 2024
		Natural Gas(d)	$	111	11.15%
Pepco - District of Columbia(e)	April 13, 2023 (amended February 27, 2024)	Electric	$	186	10.50%	Fourth quarter of 2024
DPL - Delaware	September 20, 2024	Natural Gas(f)	$	36	10.65%	First quarter of 2026

__________

(a)On March 13, 2024, ComEd filed its Refiled Grid Plan with the ICC and on March 15, 2024, ComEd filed a petition to adjust its multi-year rate plan to be aligned with ComEd’s Refiled Grid Plan. The adjusted rate plan incorporates changes in the Refiled Grid Plan, which was updated in ComEd's July 31, 2024 surrebuttal testimony and updated again on August 13, 2024, to request a $667 million increase in revenue requirements over four years above those granted in the ICC’s January 10, 2024 amendatory order. The requested year-over-year increases are $309 million in 2024, $95 million in 2025, $128 million in 2026, and $135 million in 2027. A final order on both the Refiled Grid Plan and the adjusted rate plan petition is expected by December 2024 with new rates effective on or before January 1, 2025.

(b)On April 26, 2024, ComEd filed its proposed Delivery Reconciliation Amount, which was updated in ComEd's surrebuttal testimony on September 11, 2024, of $624 million under Rider DSPR which allows for the reconciliation of the revenue requirement in effect. The 2024 filing reconciles those rates with the actual delivery service costs incurred in 2023. The final order is expected in the fourth quarter of 2024 and the reconciliation amount will adjust customer rates in 2025.

(c)PECO requested an annual electric revenue requirement increase of $464 million, which is partially offset by a one-time credit of $64 million in 2025.

(d)On August 30, 2024, PECO and the settling parties filed with the PAPUC two petitions for non-unanimous joint settlements, which included among other things, an increase of $354 million and $78 million in annual distribution service revenue for electric and gas, respectively. No overall ROE was specified in either settlement. On October 15, 2024, the Administrative Law Judges (ALJs) issued Recommended Decisions approving the requested revenue increases of $354 million for electric and $78 million for gas. On October 22, 2024, PECO filed an exception to the ALJs ruling against the Gas Weather Normalization Adjustment. The Commission’s final order, addressing the exception, is expected by December 2024. If approved, the new electric and gas rates take effect January 1, 2025.

(e)Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 submitted to the DCPSC. Pepco requested total electric revenue requirement increases of $116 million, $35 million, and $35 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support the District of Columbia’s climate and clean energy goals.

(f)DPL can implement interim rates on April 20, 2025, subject to refund.

Transmission Formula Rates

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

54

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).

For 2024, the following increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:

Registrant(a)	Initial Revenue Requirement Increase		Annual Reconciliation (Decrease) Increase		Total Revenue Requirement Increase			Allowed Return on Rate Base(b)		Allowed ROE(c)
ComEd	$	32	$	(12)	$	20		8.14	%	11.50	%
PECO	$	2	$	3	$	5		7.45	%	10.35	%
BGE	$	42	$	13	$	53	(d)	7.47	%	10.50	%
Pepco	$	58	$	15	$	73		7.62	%	10.50	%
DPL	$	7	$	17	$	24		7.23	%	10.50	%
ACE	$	14	$	18	$	32		7.11	%	10.50	%

__________

(a)All rates are effective June 1, 2024 - May 31, 2025, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariffs.

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

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

(d)The increase in BGE's transmission revenue requirement includes a $2 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

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

On February 3, 2022, the ICC approved a tariff that establishes the process under which ComEd reconciled its 2022 and 2023 rate year revenue requirements with actual costs. Those reconciliation amounts are determined using the same process used for prior reconciliations under the performance-based electric distribution formula rate. Using that process, for the rate years 2022 and 2023 ComEd will ultimately collect revenues from customers reflecting each year’s actual recoverable costs, year-end rate base, and a weighted average debt and equity return on distribution rate base, with the ROE component based on the annual average of the monthly yields of the 30-year U.S. Treasury bonds plus 580 basis points. In April 2023, ComEd filed its first petition with the ICC to reconcile its 2022 actual costs with the approved revenue requirement that was in effect in 2022; the final order was issued on November 30, 2023, for rates beginning January 2024. On April 26, 2024, ComEd filed with the ICC its 2023 actual costs with the approved revenue requirement that was in effect in 2023; the final order is expected in the fourth quarter of 2024, for rates beginning January 2025.

Beginning in 2024, ComEd will recover from retail customers, subject to certain exceptions, the costs it incurs to provide electric delivery services either through its electric distribution rate or other recovery mechanisms authorized by CEJA. On January 17, 2023, ComEd filed a petition with the ICC seeking approval of a MRP for 2024-2027. The MRP supports a multi-year grid plan (Grid Plan), also filed on January 17, covering planned

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the MRP are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105% of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review during 2025.

On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s Grid Plan as non-compliant with certain requirements of CEJA, and required ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the final order. In the absence of an approved Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This resulted in a total cumulative revenue requirement increase of $501 million, a $986 million total revenue reduction from the requested cumulative revenue requirement increase but remains subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC did not approve a previously proposed phase-in of the ICC's approved year-over-year revenue increases, and it also denied ComEd's ability to earn a return on its pension asset.

On December 22, 2023, ComEd filed an application for rehearing on several findings in the final order including the use of the 2022 year-end rate base to establish forecast revenue requirements for 2024-2027, ROE, pension asset return, and capital structure. On January 10, 2024, ComEd’s application for rehearing was denied on all issues except for the order’s use of the 2022 year-end rate base. On January 31, 2024, the ICC granted ComEd's motion seeking additional clarification on the scope on rehearing, generally accepting ComEd's proposal and confirming that the rehearing will determine if the forecasted year-end 2023 rate base should be used to set rates for 2024 through 2027 until a refiled Grid Plan is approved. On April 18, 2024, the ICC issued its final order on rehearing and approved increased revenue requirements for 2024-2027.

On January 10, 2024, ComEd also filed an appeal in the Illinois Appellate Court of the issues on which rehearing was denied, including but not limited to the allowed ROE and denial of a return on ComEd’s pension asset. There is no deadline by when the appellate court must rule. On March 7, 2024, the ICC adopted an interim order on scheduling, which confirmed that it intends to issue a final order on ComEd’s Refiled Grid Plan by the end of 2024 and that it will implement rates that will go into effect January 1, 2025, inclusive of a Grid Plan. On March 13, 2024, ComEd filed its Refiled Grid Plan with supporting testimony and schedules with the ICC. The Refiled Grid Plan is designed to meet or exceed every requirement identified by the ICC in its December order that rejected ComEd’s initial Grid Plan. On March 15, 2024, ComEd filed a petition to adjust its MRP to authorize increased rates consistent with the Refiled Grid Plan. Staff and Intervenor direct testimony was filed in May 2024. ComEd filed rebuttal and surrebuttal testimony in June and July, respectively, which provided, among other things, defense of its Refiled Grid Plan capital investments. Evidentiary hearings were held in August; the ALJs' proposed order was issued on October 18, 2024. ComEd has completed and placed in service additional utility plant assets in 2023 and 2024 and will continue to complete and place in service additional utility plant assets prior to the approval of the new Grid Plan. There are still significant unknowns, but ComEd does not currently believe that it is probable that the initially uncollected depreciation or return on the recently completed plant will ultimately be disallowed.

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

Carbon Mitigation Credit

CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

nuclear-powered generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. Beginning with the June 2022 monthly billing period, ComEd began issuing credits and/or charges to its retail customers under its new CMC rider. A regulatory asset 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 as of September 30, 2024 is $183 million.

Under CEJA, the costs of procuring CMCs, including carrying costs, are recovered through a rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). As originally approved by the ICC, Rider CFRA provides for an annual reconciliation and true-up to actual costs incurred or credits received by ComEd to purchase CMCs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods. The difference between the net payments to (or receivables from) ComEd ratepayers and the credits received by ComEd to purchase CMCs is recorded to Purchased power expense with an offset to the regulatory asset (or regulatory liability). On December 21, 2022, ComEd filed an amendment to Rider CFRA proposing that it recover costs or provide credits faster than the tariff allows, implement monthly reconciliations, and allow ComEd to adjust Rider CFRA rates based not only on anticipated differences but also past payments or credits, and implement monthly reconciliations beginning with the June 2023 delivery period. The ICC approved the proposal on January 19, 2023. In addition, on March 24, 2023, ComEd submitted revisions to Rider CFRA which clarified the methodology for calculating interest to be included in the annual reconciliation associated with the June 2022 through May 2023 delivery year. The ICC approved the proposal on April 20, 2023. 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 CMCs during the delivery year beginning June 1, 2022 and extending through May 31, 2023.

Beneficial Electrification Plan

On March 23, 2023, the ICC issued its final order approving the beneficial electrification plan (BE Plan) for ComEd. The ICC rejected ComEd’s request to treat a large portion of beneficial electrification costs as a regulatory asset and ordered ComEd to seek cost recovery through the multi-year rate plan filing for 2024 and 2025, and the final formula rate reconciliation docket for 2023, rather than through a separate charge. The order also authorized an overall annual budget of $77 million per year for the three-year plan period (2023 through 2025), with flexibility to roll forward unused funds to future years within the same plan period. On April 18, 2023, ComEd filed an application for rehearing in the beneficial electrification plan docket. The Chicago Transit Authority and City of Chicago, jointly, and the Office of the Illinois Attorney General (ILAG) also filed applications for rehearing. On April 27, 2023, ICC staff filed a motion for clarification, seeking clarification from the ICC on the precise budget described in the final order. On May 8, 2023, the ICC denied all applications for rehearing, and entered an amendatory order regarding the annual beneficial electrification plan budgets. ComEd has been directed to use good faith efforts to spend $77 million annually. ComEd subsequently filed its compliance filing in May 2023, detailing project related spending, clarifying the procedure that will be used to seek stakeholder feedback related to beneficial electrification pilot programs, and including the timeline for tariff changes required to implement the programs. ComEd and the ILAG both filed appeals of the ICC’s interim order that addressed the permissible scope of utility beneficial electrification programs outside of transportation and the rate impact cap. The ILAG also filed an appeal seeking reversal of portions of the ICC’s final decision. The final order partly mooted ComEd’s appeal of the interim order and ComEd has decided not to pursue the other issues. As such, ComEd moved to voluntarily dismiss its appeal and the appellate court granted that request. The ILAG consolidated their appeals; briefing has been completed. Oral arguments are scheduled for December 11, 2024. Any ruling on the appeals, even a negative ruling removing programs from the BE Plan or lowering the overall budget of the BE Plan, will only impact forward-looking costs.

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 in 2023 through 2040 to achieve these energy efficiency MWh savings goals, which will be deferred as a separate

57

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.

Energy Efficiency Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on May 30, 2024. The filing establishes the revenue requirement used to set the rates that will take effect in January 2025 after the ICC's review and approval. The requested revenue requirement update is based on a reconciliation of the 2023 actual costs plus projected 2025 expenditures. The ICC's final order is expected in the fourth quarter of 2024.

Initial Revenue Requirement Increase		Annual Reconciliation Decrease		Total Revenue Requirement Increase		Requested Return on Rate Base(a)		Requested ROE
$	66	$	(8)	$	58	7.02	%	9.89	%

__________

(a)The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.02% inclusive of an allowed ROE of 9.89%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 2023 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 7.25% inclusive of an allowed ROE of 10.34%, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals.

New Jersey Regulatory Matters

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

As of September 30, 2024, the $10 million liability for the contract termination fee is included in Other current liabilities in Exelon's Consolidated Balance Sheet and PPA termination obligation in PHI's and ACE's Consolidated Balance Sheets. For the nine months ended September 30, 2024 and 2023, ACE has respectively paid $40 million and $65 million of the liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Cash Flows.

Other Federal Regulatory Matters

FERC Audit (Exelon and ComEd). The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extends back to January 1, 2017.

On July 27, 2023, FERC issued a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. On August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place.

On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The final settlement is subject to FERC approval. The existing loss estimate is reflected in Exelon and ComEd's financial statements as of September 30, 2024.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2023, unless noted below. See Note 3 — Regulatory Matters of the 2023 Form 10-K for additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets decreased $414 million primarily due to a decrease of $490 million in the CMC regulatory asset. Regulatory liabilities increased $1,155 million primarily due to an increase of $1,029 million in the Decommissioning the Regulatory Agreement Units regulatory liability.

PECO. Regulatory assets increased $69 million primarily due to an increase of $96 million in the Deferred Income Taxes regulatory asset. Regulatory liabilities increased $53 million primarily due to an increase of $60 million in the Decommissioning the Regulatory Agreement Units regulatory liability.

BGE. Regulatory liabilities decreased $102 million primarily due to a decrease of $101 million in the Deferred income taxes regulatory liability.

Pepco. Regulatory assets increased $29 million primarily due to an increase of $27 million in the Multi-year plan reconciliations regulatory asset and an increase of $9 million in the Revenue deferral mechanism regulatory asset, as a result of the Pepco Maryland multi-year plan order issued on June 10, 2024. Regulatory liabilities decreased $46 million primarily due to a decrease of $46 million in the Deferred income taxes regulatory liability.

DPL. Regulatory liabilities decreased $37 million primarily due to a decrease of $20 million in the Deferred income taxes regulatory liability.

ACE. Regulatory assets decreased $10 million primarily due to a decrease of $37 million in the Electric energy and natural gas costs regulatory asset. Regulatory liabilities increased $10 million primarily due to an increase of $12 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, 2024 and December 31, 2023.

	Exelon		ComEd(a)		BGE(b)		PHI		Pepco(c)		DPL(d)		ACE(e)
September 30, 2024	$	126	$	43	$	22	$	61	$	47	$	1	$	13
December 31, 2023	110		32		33		45		34		1		10

__________

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

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

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

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

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

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.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Revenue from Contracts with Customers

See Note 4 — Revenue from Contracts with Customers of the 2023 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.

Contract Liabilities

The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities in Other current liabilities and Other noncurrent deferred credits and other liabilities in their Consolidated Balance Sheets.

For Pepco, DPL, and ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement ("Agreement") with an unrelated owner and manager of communication infrastructure, as well as additional consideration received for the payment option amendment ("Amendment") executed during the fourth quarter of 2023, which is discussed in further detail within Note 4 — Revenue from Contracts with Customers of the 2023 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, 2024 and 2023. At September 30, 2024 and December 31, 2023, ComEd's, PECO's, and BGE's contract liabilities were immaterial.

	Exelon(a)		PHI(a)		Pepco(a)		DPL		ACE
Balance at December 31, 2023	$	133	$	133	$	107	$	13	$	13
Revenues recognized	(2)		(2)		(2)		—		—
Balance at March 31, 2024	$	131	$	131	$	105	$	13	$	13
Revenues recognized	(1)		(1)		(1)		—		—
Balance at June 30, 2024	$	130	$	130	$	104	$	13	$	13
Revenues recognized	(2)		(2)		(2)		—		—
Balance at September 30, 2024	$	128	$	128	$	102	$	13	$	13
	Exelon(a)		PHI(a)		Pepco(a)		DPL		ACE
Balance at December 31, 2022	$	101	$	101	$	81	$	10	$	10
Revenues recognized	(1)		(1)		(1)		—		—
Balance at March 31, 2023	$	100	$	100	$	80	$	10	$	10
Revenues recognized	(2)		(2)		(2)		—		—
Balance at June 30, 2023	$	98	$	98	$	78	$	10	$	10
Revenues recognized	(2)		(2)		(1)		—		(1)
Balance at September 30, 2023	$	96	$	96	$	77	$	10	$	9

__________

(a)Revenues recognized in the three and nine months ended September 30, 2024 and 2023, were included in the contract liabilities at December 31, 2023 and 2022, 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, 2024. 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.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Revenue from Contracts with Customers

Year	Exelon		PHI		Pepco		DPL		ACE
2024	$	1	$	1	$	1	$	—	$	—
2025	7		7		5		1		1
2026	6		6		5		1		—
2027	5		5		5		—		—
2028 and thereafter	109		109		86		11		12
Total	$	128	$	128	$	102	$	13	$	13

Revenue Disaggregation

The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 4 — Segment Information for the presentation of the Registrants' revenue disaggregation.

4. Segment Information (All Registrants)

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

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 Utility Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to the segments based on net income.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2024 and 2023 is as follows:

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

Three Months Ended September 30, 2024 and 2023

	ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2024
Electric revenues	$	2,229	$	960	$	925	$	1,836	$	—	$	(6)	$	5,944
Natural gas revenues	—		70		119		23		—		(2)		210
Shared service and other revenues	—		—		—		3		441		(444)		—
Total operating revenues	$	2,229	$	1,030	$	1,044	$	1,862	$	441	$	(452)	$	6,154
2023
Electric revenues	$	2,268	$	970	$	836	$	1,747	$	—	$	(28)	$	5,793
Natural gas revenues	—		67		96		24		—		—		187
Shared service and other revenues	—		—		—		2		445		(447)		—
Total operating revenues	$	2,268	$	1,037	$	932	$	1,773	$	445	$	(475)	$	5,980
Intersegment revenues(c):
2024	$	2	$	4	$	3	$	3	$	438	$	(450)	$	—
2023	9		2		2		2		443		(458)		—
Depreciation and amortization:
2024	$	387	$	108	$	162	$	235	$	16	$	—	$	908
2023	357		100		161		257		15		—		890
Operating expenses:
2024	$	1,731	$	868	$	949	$	1,439	$	439	$	(465)	$	4,961
2023	1,738		847		835		1,440		475		(478)		4,857
Interest expense, net:
2024	$	128	$	58	$	57	$	95	$	158	$	—	$	496
2023	119		52		47		80		139		—		437
Income Taxes:
2024	$	36	$	(4)	$	4	$	72	$	(58)	$	—	$	50
2023	94		3		11		49		(90)		—		67
Net income (loss):
2024	$	360	$	117	$	45	$	278	$	(93)	$	—	$	707
2023	333		146		45		232		(41)		(15)		700
Capital Expenditures:
2024	$	508	$	382	$	365	$	440	$	—	$	—	$	1,695
2023	664		361		330		488		12		—		1,855

______________

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

(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.

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

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

PHI:

	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2024
Electric revenues	$	861	$	439	$	540	$	—	$	(4)	$	1,836
Natural gas revenues	—		23		—		—		—		23
Shared service and other revenues	—		—		—		103		(100)		3
Total operating revenues	$	861	$	462	$	540	$	103	$	(104)	$	1,862
2023
Electric revenues	$	822	$	426	$	502	$	—	$	(3)	$	1,747
Natural gas revenues	—		24		—		—		—		24
Shared service and other revenues	—		—		—		103		(101)		2
Total operating revenues	$	822	$	450	$	502	$	103	$	(104)	$	1,773
Intersegment revenues(c):
2024	$	2	$	2	$	1	$	103	$	(105)	$	3
2023	1		2		—		103		(104)		2
Depreciation and amortization:
2024	$	102	$	62	$	67	$	4	$	—	$	235
2023	112		62		77		6		—		257
Operating expenses:
2024	$	650	$	377	$	410	$	106	$	(104)	$	1,439
2023	658		386		394		105		(103)		1,440
Interest expense, net:
2024	$	50	$	22	$	21	$	3	$	(1)	$	95
2023	41		18		19		3		(1)		80
Income Taxes:
2024	$	32	$	14	$	30	$	(4)	$	—	$	72
2023	21		8		23		(3)		—		49
Net income (loss):
2024	$	140	$	55	$	83	$	—	$	—	$	278
2023	120		43		71		(2)		—		232
Capital Expenditures:
2024	$	218	$	136	$	85	$	1	$	—	$	440
2023	227		158		101		2		—		488

__________

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

(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.

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

63

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

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

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

	Three Months Ended September 30, 2024
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	1,117	$	641	$	558	$	1,016	$	426	$	267	$	323
Small commercial & industrial	603		153		96		203		52		69		82
Large commercial & industrial	286		73		154		365		281		31		53
Public authorities & electric railroads	11		7		8		18		9		4		5
Other(a)	280		74		110		225		85		70		71
Total electric revenues(b)	$	2,297	$	948	$	926	$	1,827	$	853	$	441	$	534
Natural gas revenues
Residential	$	—	$	44	$	58	$	11	$	—	$	11	$	—
Small commercial & industrial	—		17		11		6		—		6		—
Large commercial & industrial	—		—		32		1		—		1		—
Transportation	—		7		—		4		—		4		—
Other(c)	—		2		3		1		—		1		—
Total natural gas revenues(d)	$	—	$	70	$	104	$	23	$	—	$	23	$	—
Total revenues from contracts with customers	$	2,297	$	1,018	$	1,030	$	1,850	$	853	$	464	$	534
Other revenues
Revenues from alternative revenue programs	$	(76)	$	5	$	9	$	8	$	5	$	(3)	$	6
Other electric revenues(e)	8		7		4		4		3		1		—
Other natural gas revenues(e)	—		—		1		—		—		—		—
Total other revenues	$	(68)	$	12	$	14	$	12	$	8	$	(2)	$	6
Total revenues for reportable segments	$	2,229	$	1,030	$	1,044	$	1,862	$	861	$	462	$	540

64

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, 2023
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	1,047	$	654	$	512	$	959	$	405	$	255	$	299
Small commercial & industrial	540		148		86		199		54		70		75
Large commercial & industrial	263		67		144		386		303		32		51
Public authorities & electric railroads	11		7		7		16		9		3		4
Other(a)	265		80		104		201		67		67		68
Total electric revenues(b)	$	2,126	$	956	$	853	$	1,761	$	838	$	427	$	497
Natural gas revenues
Residential	$	—	$	43	$	57	$	12	$	—	$	12	$	—
Small commercial & industrial	—		16		10		7		—		7		—
Large commercial & industrial	—		—		25		1		—		1		—
Transportation	—		7		—		3		—		3		—
Other(c)	—		1		4		1		—		1		—
Total natural gas revenues(d)	$	—	$	67	$	96	$	24	$	—	$	24	$	—
Total revenues from contracts with customers	$	2,126	$	1,023	$	949	$	1,785	$	838	$	451	$	497
Other revenues
Revenues from alternative revenue programs	$	135	$	11	$	(22)	$	(15)	$	(18)	$	(2)	$	5
Other electric revenues(e)	7		3		4		3		2		1		—
Other natural gas revenues(e)	—		—		1		—		—		—		—
Total other revenues	$	142	$	14	$	(17)	$	(12)	$	(16)	$	(1)	$	5
Total revenues for reportable segments	$	2,268	$	1,037	$	932	$	1,773	$	822	$	450	$	502

__________

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

(b)Includes operating revenues from affiliates in 2024 and 2023 respectively of:

•$2 million, $9 million at ComEd

•$3 million, $2 million at PECO

•$2 million, $1 million at BGE

•$3 million, $2 million at PHI

•$2 million, $1 million at Pepco

•$2 million, $2 million at DPL

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

(c)Includes off-system natural gas sales.

(d)Includes operating revenues from affiliates in 2024 and 2023 respectively of:

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

•$1 million, $1 million at BGE

(e)Includes late payment charge revenues.

65

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

Nine Months Ended September 30, 2024 and 2023

	ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2024
Electric revenues	$	6,403	$	2,537	$	2,588	$	4,809	$	—	$	(17)	$	16,320
Natural gas revenues	—		438		680		122		—		(3)		1,237
Shared service and other revenues	—		—		—		7		1,369		(1,376)		—
Total operating revenues	$	6,403	$	2,975	$	3,268	$	4,938	$	1,369	$	(1,396)	$	17,557
2023
Electric revenues	$	5,836	$	2,484	$	2,322	$	4,459	$	—	$	(45)	$	15,056
Natural gas revenues	—		493		664		150		—		(3)		1,304
Shared service and other revenues	—		—		—		6		1,316		(1,322)		—
Total operating revenues	$	5,836	$	2,977	$	2,986	$	4,615	$	1,316	$	(1,370)	$	16,360
Intersegment revenues(c):
2024	$	6	$	7	$	7	$	7	$	1,362	$	(1,389)	$	—
2023	14		6		6		7		1,310		(1,343)		—
Depreciation and amortization:
2024	$	1,124	$	318	$	474	$	716	$	49	$	—	$	2,681
2023	1,045		297		487		741		46		—		2,616
Operating expenses:
2024	$	5,192	$	2,471	$	2,751	$	3,977	$	1,382	$	(1,425)	$	14,348
2023	4,472		2,436		2,503		3,864		1,521		(1,367)		13,429
Interest expense, net:
2024	$	374	$	170	$	159	$	279	$	466	$	(2)	$	1,446
2023	357		149		135		238		402		(4)		1,277
Income taxes:
2024	$	85	$	9	$	32	$	158	$	(126)	$	—	$	158
2023	235		8		76		103		(149)		1		274
Net income (loss):
2024	$	823	$	356	$	353	$	603	$	(322)	$	—	$	1,813
2023	822		410		286		490		(275)		(22)		1,711
Capital expenditures:
2024	$	1,619	$	1,125	$	1,033	$	1,343	$	41	$	—	$	5,161
2023	1,926		1,068		986		1,510		50		—		5,540
Total assets:
September 30, 2024	$	44,718	$	16,748	$	15,038	$	27,672	$	5,804	$	(3,910)	$	106,070
December 31, 2023	42,827		15,595		14,184		26,903		6,374		(4,337)		101,546

__________

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

(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.

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

66

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

PHI:

	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2024
Electric revenues	$	2,320	$	1,221	$	1,280	$	—	$	(12)	$	4,809
Natural gas revenues	—		122		—		—		—		122
Shared service and other revenues	—		—		—		328		(321)		7
Total operating revenues	$	2,320	$	1,343	$	1,280	$	328	$	(333)	$	4,938
2023
Electric revenues	$	2,174	$	1,123	$	1,172	$	1	$	(11)	$	4,459
Natural gas revenues	—		150		—		—		—		150
Shared service and other revenues	—		—		—		309		(303)		6
Total operating revenues	$	2,174	$	1,273	$	1,172	$	310	$	(314)	$	4,615
Intersegment revenues(c):
2024	$	5	$	5	$	2	$	328	$	(333)	$	7
2023	5		5		1		309		(313)		7
Depreciation and amortization:
2024	$	307	$	183	$	214	$	12	$	—	$	716
2023	329		182		212		18		—		741
Operating expenses:
2024	$	1,824	$	1,099	$	1,052	$	335	$	(333)	$	3,977
2023	1,810		1,079		971		318		(314)		3,864
Interest expense, net:
2024	$	142	$	69	$	59	$	10	$	(1)	$	279
2023	122		53		52		9		2		238
Income taxes:
2024	$	74	$	39	$	48	$	(3)	$	—	$	158
2023	43		25		40		(5)		—		103
Net income (loss):
2024	$	323	$	156	$	133	$	(9)	$	—	$	603
2023	249		128		122		(9)		—		490
Capital expenditures:
2024	$	672	$	404	$	265	$	2	$	—	$	1,343
2023	710		416		376		8		—		1,510
Total assets:
September 30, 2024	$	11,602	$	6,204	$	5,329	$	4,573	$	(36)	$	27,672
December 31, 2023	11,194		5,966		5,157		4,627		(41)		26,903

__________

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

(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.

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

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

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

67

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.

	Nine Months Ended September 30, 2024
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	3,017	$	1,683	$	1,556	$	2,537	$	1,085	$	725	$	727
Small commercial & industrial	1,755		407		274		519		141		191		187
Large commercial & industrial	875		191		425		1,034		794		91		149
Public authorities & electric railroads	43		21		24		52		26		12		14
Other(a)	803		221		303		623		224		198		206
Total electric revenues(b)	$	6,493	$	2,523	$	2,582	$	4,765	$	2,270	$	1,217	$	1,283
Natural gas revenues
Residential	$	—	$	300	$	418	$	72	$	—	$	72	$	—
Small commercial & industrial	—		106		76		29		—		29		—
Large commercial & industrial	—		—		143		4		—		4		—
Transportation	—		20		—		12		—		12		—
Other(c)	—		11		12		5		—		5		—
Total natural gas revenues(d)	$	—	$	437	$	649	$	122	$	—	$	122	$	—
Total revenues from contracts with customers	$	6,493	$	2,960	$	3,231	$	4,887	$	2,270	$	1,339	$	1,283
Other revenues
Revenues from alternative revenue programs	$	(100)	$	3	$	28	$	40	$	42	$	1	$	(3)
Other electric revenues(e)	10		11		7		11		8		3		—
Other natural gas revenues(e)	—		1		2		—		—		—		—
Total other revenues	$	(90)	$	15	$	37	$	51	$	50	$	4	$	(3)
Total revenues for reportable segments	$	6,403	$	2,975	$	3,268	$	4,938	$	2,320	$	1,343	$	1,280

68

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, 2023
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	2,744	$	1,617	$	1,308	$	2,181	$	954	$	626	$	601
Small commercial & industrial	1,363		415		253		503		134		189		180
Large commercial & industrial	553		196		412		1,099		838		98		163
Public authorities & electric railroads	33		23		22		49		25		11		13
Other(a)	716		219		303		563		187		186		194
Total electric revenues(b)	$	5,409	$	2,470	$	2,298	$	4,395	$	2,138	$	1,110	$	1,151
Natural gas revenues
Residential	$	—	$	335	$	406	$	88	$	—	$	88	$	—
Small commercial & industrial	—		123		66		40		—		40		—
Large commercial & industrial	—		1		124		3		—		3		—
Transportation	—		20		—		11		—		11		—
Other(c)	—		12		28		8		—		8		—
Total natural gas revenues(d)	$	—	$	491	$	624	$	150	$	—	$	150	$	—
Total revenues from contracts with customers	$	5,409	$	2,961	$	2,922	$	4,545	$	2,138	$	1,260	$	1,151
Other revenues
Revenues from alternative revenue programs	$	405	$	1	$	47	$	59	$	28	$	10	$	21
Other electric revenues(e)	22		13		12		11		8		3		—
Other natural gas revenues(e)	—		2		5		—		—		—		—
Total other revenues	$	427	$	16	$	64	$	70	$	36	$	13	$	21
Total revenues for reportable segments	$	5,836	$	2,977	$	2,986	$	4,615	$	2,174	$	1,273	$	1,172

__________

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

(b)Includes operating revenues from affiliates in 2024 and 2023 respectively of:

•$6 million, $14 million at ComEd

•$5 million, $5 million at PECO

•$4 million, $4 million at BGE

•$7 million, $7 million at PHI

•$5 million, $5 million at Pepco

•$5 million, $5 million at DPL

•$2 million, $1 million at ACE

(c)Includes off-system natural gas sales.

(d)Includes operating revenues from affiliates in 2024 and 2023 respectively of:

•$2 million, $1 million at PECO

•$3 million, $2 million at BGE

(e)Includes late payment charge revenues.

69

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, 2024
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at June 30, 2024	$	372	$	112	$	112	$	45	$	103	$	53	$	16	$	34
Plus: Current period provision for expected credit losses(a)(b)(c)	84		16		28		20		20		12		4		4
Less: Write-offs(d), net of recoveries(e)	30		7		5		5		13		7		3		3
Balance at September 30, 2024	$	426	$	121	$	135	$	60	$	110	$	58	$	17	$	35
	Three Months Ended September 30, 2023
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at June 30, 2023	$	323	$	67	$	101	$	50	$	105	$	50	$	21	$	34
Plus: Current period provision for expected credit losses	72		24		13		9		26		11		6		9
Less: Write-offs, net of recoveries	54		15		19		7		13		5		4		4
Balance at September 30, 2023	$	341	$	76	$	95	$	52	$	118	$	56	$	23	$	39
	Nine Months Ended September 30, 2024
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2023	$	317	$	69	$	95	$	46	$	107	$	52	$	19	$	36
Plus: Current period provision for expected credit losses(c)(f)(g)	221		77		63		34		47		30		8		9
Less: Write-offs(d)(h)(i), net of recoveries(e)	112		25		23		20		44		24		10		10
Balance at September 30, 2024	$	426	$	121	$	135	$	60	$	110	$	58	$	17	$	35
	Nine Months Ended September 30, 2023
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2022	$	327	$	59	$	105	$	54	$	109	$	47	$	21	$	41
Plus: Current period provision for expected credit losses	144		45		32		23		44		24		10		10
Less: Write-offs, net of recoveries	130		28		42		25		35		15		8		12
Balance at September 30, 2023	$	341	$	76	$	95	$	52	$	118	$	56	$	23	$	39

_________

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

(b)For BGE and ACE, the change is primarily a result of changes in customer risk profile. For BGE, also reflects increased receivable balances.

(c)For DPL, the decrease is primarily a result of decreased receivable balances.

(d)For PECO, the decrease is primarily a result of decreased disconnection activities.

(e)Recoveries were not material to the Registrants.

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

(g)For BGE and Pepco, the increase is primarily a result of changes in customer risk profile. For BGE, also reflects increased receivable balances.

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

(i)For Pepco and DPL, the increase is primarily attributable to unfavorable customer payment behavior.

70

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Accounts Receivable

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

	Three Months Ended September 30, 2024
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at June 30, 2024	$	108	$	29	$	20	$	5	$	54	$	34	$	7	$	13
Plus: Current period provision (benefit) for expected credit losses(a)	7		10		1		3		(7)		(8)		—		1
Less: Write-offs, net of recoveries(b)	4		—		1		2		1		—		—		1
Balance at September 30, 2024	$	111	$	39	$	20	$	6	$	46	$	26	$	7	$	13
	Three Months Ended September 30, 2023
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at June 30, 2023	$	87	$	18	$	8	$	8	$	53	$	31	$	9	$	13
Plus: Current period provision (benefit) for expected credit losses	6		3		2		3		(2)		(2)		—		—
Less: Write-offs, net of recoveries	5		1		2		2		—		—		—		—
Balance at September 30, 2023	$	88	$	20	$	8	$	9	$	51	$	29	$	9	$	13
	Nine Months Ended September 30, 2024
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2023	$	82	$	17	$	8	$	7	$	50	$	28	$	8	$	14
Plus: Current period provision (benefit) for expected credit losses(a)(c)	43		25		15		4		(1)		(2)		(1)		2
Less: Write-offs, net of recoveries(b)	14		3		3		5		3		—		—		3
Balance at September 30, 2024	$	111	$	39	$	20	$	6	$	46	$	26	$	7	$	13
	Nine Months Ended September 30, 2023
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2022	$	82	$	17	$	9	$	10	$	46	$	25	$	7	$	14
Plus: Current period provision for expected credit losses	21		6		3		5		7		4		2		1
Less: Write-offs, net of recoveries	15		3		4		6		2		—		—		2
Balance at September 30, 2023	$	88	$	20	$	8	$	9	$	51	$	29	$	9	$	13

_________

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

(b)Recoveries were not material to the Registrants.

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

Unbilled Customer Revenue

The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets at September 30, 2024 and December 31, 2023.

	Unbilled customer revenues(a)
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2024	$	812	$	338	$	149	$	135	$	190	$	83	$	46	$	61
December 31, 2023	991		351		185		208		247		109		64		74

__________

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

71

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Accounts Receivable

Other Purchases of Customer and Other Accounts Receivables

For the nine months ended September 30, 2024 and 2023 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, 2024	$	3,177	$	750	$	854	$	606	$	967	$	607	$	191	$	169
Nine months ended September 30, 2023	3,124		726		843		628		927		600		174		153

6. Income Taxes (All Registrants)

Rate Reconciliation

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

	Three Months Ended September 30, 2024(a)
	Exelon		ComEd(b)		PECO(c)		BGE(b)		PHI		Pepco		DPL		ACE
U.S. Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	5.7		7.6		(2.1)		6.5		6.5		6.2		6.3		7.4
Plant basis differences	(4.8)		(0.8)		(19.5)		(0.8)		(0.8)		(1.2)		(0.8)		—
Excess deferred tax amortization	(14.0)		(16.6)		(2.6)		(18.6)		(5.5)		(6.7)		(5.9)		(1.6)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.1)		(0.1)		—		(0.1)		(0.1)		—		(0.1)		(0.1)
Tax credits	(0.9)		(2.6)		—		(0.6)		(0.6)		(0.5)		(0.6)		(0.5)
Other	(0.3)		0.6		(0.3)		0.8		0.1		(0.2)		0.4		0.3
Effective income tax rate	6.6	%	9.1	%	(3.5)	%	8.2	%	20.6	%	18.6	%	20.3	%	26.5	%

	Three Months Ended September 30, 2023(a)
	Exelon		ComEd		PECO(c)		BGE		PHI		Pepco		DPL		ACE
U.S. Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit (d)	(2.7)		7.8		(1.2)		6.6		6.2		5.5		6.1		7.0
Plant basis differences	(4.4)		(0.4)		(15.6)		(0.2)		(1.5)		(2.4)		(0.9)		(0.5)
Excess deferred tax amortization	(6.4)		(5.3)		(2.4)		(5.4)		(8.0)		(9.2)		(10.0)		(3.1)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.1)		(0.1)		—		(0.1)		(0.1)		—		(0.1)		(0.1)
Tax credits	(0.5)		(1.2)		—		(2.0)		(0.5)		(0.6)		(0.4)		(0.3)
Other	1.8		0.2		0.2		(0.3)		0.3		0.6		—		0.5
Effective income tax rate	8.7	%	22.0	%	2.0	%	19.6	%	17.4	%	14.9	%	15.7	%	24.5	%

__________

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

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

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

72

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Income Taxes

(d)For Exelon, the lower state income taxes, net of federal income tax expense, is primarily due to the long-term marginal state income tax rate change of $54 million.

	Nine Months Ended September 30, 2024(a)
	Exelon		ComEd(b)		PECO(c)		BGE(b)		PHI		Pepco		DPL		ACE
U.S. Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	5.8		7.7		(1.2)		6.3		6.5		6.2		6.2		7.4
Plant basis differences	(4.2)		(0.8)		(14.7)		(1.2)		(0.9)		(1.3)		(0.9)		0.1
Excess deferred tax amortization	(14.1)		(17.4)		(2.4)		(17.6)		(5.4)		(6.8)		(5.8)		(1.6)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.1)		(0.1)		—		—		(0.1)		—		(0.1)		(0.1)
Tax credits	(0.6)		(1.4)		—		(0.4)		(0.5)		(0.4)		(0.4)		(0.4)
Other	0.2		0.4		(0.2)		0.2		0.2		(0.1)		—		0.1
Effective income tax rate	8.0	%	9.4	%	2.5	%	8.3	%	20.8	%	18.6	%	20.0	%	26.5	%

	Nine Months Ended September 30, 2023(a)
	Exelon		ComEd		PECO(c)		BGE		PHI		Pepco		DPL		ACE
U.S. Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit(d)	2.8		7.8		(1.3)		6.5		6.1		5.5		6.2		6.9
Plant basis differences	(4.3)		(0.4)		(15.5)		(0.5)		(1.6)		(2.5)		(1.0)		(0.5)
Excess deferred tax amortization	(6.6)		(5.5)		(2.4)		(5.4)		(7.7)		(9.2)		(9.4)		(2.6)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.1)		(0.1)		—		(0.1)		(0.1)		—		(0.1)		(0.1)
Tax credits	(0.5)		(0.7)		—		(0.7)		(0.6)		(0.7)		(0.4)		(0.3)
Other	1.5		0.1		0.1		0.2		0.3		0.6		—		0.3
Effective income tax rate	13.8	%	22.2	%	1.9	%	21.0	%	17.4	%	14.7	%	16.3	%	24.7	%

__________

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

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

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

(d)For Exelon, the lower state income taxes, net of federal income tax expense, is primarily due to the long-term marginal state income tax rate change of $54 million.

Unrecognized Tax Benefits

Exelon, PHI and ACE have the following unrecognized tax benefits at September 30, 2024 and December 31, 2023. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.

	Exelon(a)		PHI		ACE
September 30, 2024	$	85	$	38	$	1
December 31, 2023	94		51		15

__________

(a)At September 30, 2024 and December 31, 2023, Exelon's unrecognized tax benefits is inclusive of $31 million related to Constellation's share of unrecognized tax benefits for periods prior to the separation. Exelon reflected an offsetting receivable of $31 million in Other deferred debits and other assets in the Consolidated Balance Sheet for these amounts.

73

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Income Taxes

Other Tax Matters

Tax Matters Agreement (Exelon)

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

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

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

Tax Attributes. At the date of separation certain tax attributes, primarily pre-closing tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA provides that Exelon will reimburse Constellation when those allocated tax credit carryforwards are utilized. As of September 30, 2024, Exelon recorded a payable of $130 million and $201 million in Other current liabilities and Other deferred credits and other liabilities, respectively, in the Consolidated Balance Sheet for tax attribute carryforwards that are expected to be utilized and reimbursed to Constellation.

Corporate Alternative Minimum Tax (All Registrants)

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

Beginning in 2023, based on the existing statute, Exelon and each of the Utility Registrants will be subject to and will report the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets. The deferred tax asset related to the minimum tax credit carryforward will be realized to the extent Exelon’s consolidated deferred tax liabilities exceed the minimum tax credit carryforward. Exelon’s deferred tax liabilities are expected to exceed the minimum tax credit carryforward for the foreseeable future and thus no valuation allowance is required.

On September 12, 2024, the U.S. Treasury issued proposed regulations providing further guidance addressing the implementation of CAMT. The proposed regulations are consistent with Exelon’s prior interpretation and therefore there are no financial statement impacts. Exelon will continue to monitor and assess the potential financial statement impacts of final regulations or other guidance when issued.

Allocation of Tax Benefits (All Registrants)

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

The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement, for the three and nine months ended September 30, 2024, and 2023.

74

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Income Taxes

	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2024	$	30	$	15	$	14	$	16	$	9	$	5	$	2
September 30, 2023	$	13	$	19	$	—	$	10	$	4	$	—	$	2

Allocation of Income Taxes to Regulated Utilities (All Registrants)

In Q2 2024, the IRS issued a series of private letter rulings (PLR), 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 any payments received for the utilization of losses by other affiliates under a tax sharing agreement.

For the Registrants, the impact of 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 that reduce rate base for ratemaking purposes.

A PLR issued to another taxpayer may not be relied on as precedent. However, Management is analyzing this guidance and plans to work collaboratively with Exelon's regulatory commissions to address potential impacts. The Registrants will record the impact, if any, after either obtaining approval from their regulatory commissions or upon receiving their own PLRs from the IRS.

7. Retirement Benefits (All Registrants)

Defined Benefit Pension and OPEB

The majority of the 2024 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 5.19%. The majority of the 2024 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 5.17%.

During the first quarter of 2024, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2024. This valuation resulted in an increase to the pension obligation of $98 million and a decrease to the OPEB obligation of $1 million. Additionally, AOCI increased by $25 million (after-tax) and regulatory assets and liabilities increased by $66 million and $2 million, respectively.

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following tables present the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, 2024 and 2023.

75

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Retirement Benefits

	Pension Benefits				OPEB
	Three Months Ended September 30,				Three Months Ended September 30,
	2024		2023		2024		2023
Components of net periodic benefit cost
Service cost	$	43	$	39	$	6	$	6
Interest cost	141		145		24		25
Expected return on assets	(184)		(189)		(21)		(21)
Amortization of:
Prior service cost (credit)	1		1		(2)		(2)
Actuarial loss	53		41		—		—
Settlement charges	—		18		—		—
Net periodic benefit cost	$	54	$	55	$	7	$	8
	Pension Benefits				OPEB
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Components of net periodic benefit cost
Service cost	$	125	$	116	$	20	$	18
Interest cost	423		434		72		76
Expected return on assets	(552)		(566)		(63)		(63)
Amortization of:
Prior service cost (credit)	2		2		(6)		(7)
Actuarial loss (gain)	160		125		—		(1)
Settlement charges	—		18		—		—
Net periodic benefit cost	$	158	$	129	$	23	$	23

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

76

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Retirement Benefits

	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and OPEB Costs (Benefit)	2024		2023		2024		2023
Exelon	$	61	$	63	$	181	$	152
ComEd	17		6		53		19
PECO	(1)		(3)		(1)		(10)
BGE	14		14		45		42
PHI	25		25		71		74
Pepco	8		9		24		26
DPL	4		4		11		13
ACE	3		3		10		10

Defined Contribution Savings Plan

The Registrants participate in a 401(k) defined contribution savings plan that is sponsored by Exelon. The plan is qualified under applicable sections of the IRC and allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the employer contributions and employer matching contributions to the savings plan for the three and nine months ended September 30, 2024 and 2023.

	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plan Employer Contributions	2024		2023		2024		2023
Exelon	$	25	$	27	$	76	$	74
ComEd	12		12		32		31
PECO	3		3		11		10
BGE	2		3		8		8
PHI	4		5		12		13
Pepco	1		1		3		3
DPL	1		1		3		3
ACE	1		1		2		2

8. Derivative Financial Instruments (All Registrants)

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

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. At ComEd, derivative economic hedges related to commodities are recorded at fair value and offset by a corresponding regulatory asset or liability. At Exelon, derivative economic hedges related to interest rates are recorded at fair value and offsets are recorded to Electric operating revenues or Interest expense based on the activity the transaction is economically hedging. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed. At Exelon, derivative hedges that qualify and are designated as cash flow hedges are recorded at fair value and offsets are recorded to AOCI.

ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meets certain qualifications.

77

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 8 — Derivative Financial Instruments

Commodity Price Risk

The Utility Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, which are either determined to be non-derivative or classified as economic hedges. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.

Registrant	Commodity	Accounting Treatment	Hedging Instrument
ComEd	Electricity	NPNS	Fixed price contracts based on all requirements in the IPA procurement plans.
	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)	20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO	Electricity	NPNS	Fixed price contracts for default supply requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales.
BGE	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed price purchases associated with forecasted gas supply requirements.
Pepco	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
DPL	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed and index priced contracts through full requirements contracts.
	Gas	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(b)	Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE	Electricity	NPNS	Fixed price contracts for all BGS requirements through full requirements contracts.

__________

(a)See Note 3 — Regulatory Matters of the 2023 Form 10-K for additional information.

(b)The fair value of the DPL economic hedge is not material at September 30, 2024 and December 31, 2023.

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

Interest Rate and Other Risk (Exelon)

Exelon Corporate uses a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon Corporate may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. In addition, Exelon Corporate utilized interest rate swaps to manage interest rate exposure and manage potential fluctuations in Electric operating revenues at the corporate level in consolidation. These interest rate swaps are accounted for as economic hedges. A hypothetical 50 basis point change in the interest rates associated with Exelon's interest rate swaps as of September 30, 2024 would result in an immaterial impact to Exelon's Consolidated Net Income.

78

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 8 — Derivative Financial Instruments

Below is a summary of the interest rate hedge balances at September 30, 2024 and December 31, 2023.

	September 30, 2024
	Derivatives Designated as Hedging Instruments		Economic Hedges		Total
Mark-to-market derivative liabilities (noncurrent liabilities)	$	(39)	—		$	(39)
Total mark-to-market derivative liabilities	(39)		—		(39)
Total mark-to-market derivative net liabilities	$	(39)	$	—	$	(39)

	December 31, 2023
	Derivatives Designated as Hedging Instruments		Economic Hedges		Total
Other current assets	$	11	$	1	$	12
Total derivative assets	11		1		12
Mark-to-market derivative liabilities (current liabilities)	(24)		(22)		(46)
Total mark-to-market derivative liabilities	(24)		(22)		(46)
Total mark-to-market derivative net liabilities	$	(13)	$	(21)	$	(34)

Cash Flow Hedges (Interest Rate Risk)

For derivative instruments that qualify and are designated as cash flow hedges, the changes in fair value each period are initially recorded in AOCI and reclassified into earnings when the underlying transaction affects earnings.

In February 2024, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $1.3 billion upon issuance of $1.7 billion of debt. See Note 9 – Debt and Credit Agreements for additional information on the debt issuance. Prior to the termination, the 2024 year-to-date AOCI derivative gain was $33 million (net of tax). The settlements resulted in a cash receipt of $30 million. The accumulated AOCI gain of $23 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 2024, Exelon Corporate entered into $205 million notional of 5-year maturity floating-to-fixed swaps and $205 million notional of 10-year maturity floating-to-fixed swaps, for a total notional of $410 million designated as cash flow hedges. The following table provides the notional amounts outstanding held by Exelon at September 30, 2024 and December 31, 2023.

	September 30, 2024		December 31, 2023
5-year maturity floating-to-fixed swaps	$	602	$	655
10-year maturity floating-to-fixed swaps	603		655
Total	$	1,205	$	1,310

The related AOCI derivative loss for the three and nine months ended September 30, 2024 was $29 million and $30 million (net of tax), respectively. The related AOCI derivative gain for the three and nine months ended September 30, 2023 was $22 million and $31 million (net of tax), respectively. See Note 13 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.

Economic Hedges (Interest Rate and Other Risk)

Exelon Corporate executes derivative instruments to mitigate exposure to fluctuations in interest rates but for which the fair value or cash flow hedge elections were not made. For derivatives intended to serve as economic hedges, fair value is recorded on the balance sheet and changes in fair value each period are recognized in earnings or as a regulatory asset or liability, if regulatory requirements are met, each period.

Exelon Corporate entered into floating-to-fixed interest rate cap swaps to manage a portion of interest rate exposure in connection with existing borrowings. As of December 31, 2023, Exelon held $1,000 million notional

79

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 8 — Derivative Financial Instruments

of floating-to-fixed interest rate cap swaps, which matured in March 2024. Exelon received payments on the interest rate cap when the floating rate exceeded the fixed rate. Settlements received were immaterial.

Additionally, to manage potential fluctuations in Electric operating revenues related to ComEd's distribution formula rate, Exelon Corporate entered into a total $4,875 million of notional of 30-year constant maturity treasury interest rate (Corporate 30-year treasury) swaps from 2022 through 2023. The Corporate 30-year treasury swaps matured on December 31, 2023 and Exelon recorded a Mark-to-market liability of $22 million for the final settlement amount, which was paid in January 2024.

Exelon Corporate recognized the following net pre-tax mark-to-market (losses) which are also recognized in Net fair value changes related to derivatives in Exelon's Consolidated Statements of Cash Flows.

	Nine Months Ended September 30, 2024		Nine Months Ended September 30, 2023
Income Statement Location	Gain (Loss)		Gain (Loss)
Electric operating revenues	$	—	$	(21)
Interest expense	—		1
Total	$	—	$	(20)

Credit Risk

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. The amount of cash collateral received from external counterparties remained relatively consistent as of September 30, 2024 due to stable energy prices. The following table reflects the Registrants' cash collateral held from external counterparties, which is recorded in Other current liabilities on their respective Consolidated Balance Sheets, as of September 30, 2024 and December 31, 2023:

	September 30, 2024		December 31, 2023
Exelon	$	170	$	148
ComEd	167		146
PECO(a)	—		—
BGE	1		1
PHI	2		1
Pepco(b)	—		1
DPL	2		—
ACE(a)	—		—

__________

(a)PECO and ACE had less than one million in cash collateral held with external parties at September 30, 2024 and December 31, 2023.

(b)Pepco had less than one million in cash collateral held with external parties at September 30, 2024.

The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral. PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of September 30, 2024, 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, 2024, they could have been required to post collateral to their counterparties of $18 million, $37 million, and $9 million, respectively.

80

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Debt and Credit Agreements

9. Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

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

Commercial Paper

The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements at September 30, 2024 and December 31, 2023.

	Outstanding Commercial Paper at				Average Interest Rate on Commercial Paper Borrowings at
Commercial Paper Issuer	September 30, 2024		December 31, 2023		September 30, 2024		December 31, 2023
Exelon(a)	$	531	$	1,624	4.94	%	5.58	%
ComEd	$	73	$	202	4.90	%	5.53	%
PECO	$	—	$	165	—	%	5.57	%
BGE	$	—	$	336	—	%	5.59	%
PHI(b)	$	218	$	394	4.94	%	5.60	%
Pepco	$	49	$	132	4.93	%	5.59	%
DPL	$	—	$	63	—	%	5.60	%
ACE	$	169	$	199	4.94	%	5.60	%

__________

(a)Exelon Corporate had $240 million and $527 million in outstanding commercial paper borrowings at September 30, 2024 and December 31, 2023, respectively.

(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 facility, extending the maturity date to August 29, 2029. The following table reflects the credit agreements:

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

Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of September 30, 2024.

The Utility Registrants have credit facility agreements, arranged at minority and 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. These facilities expire on October 3, 2025.

81

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Debt and Credit Agreements

See Note 16 — Debt and Credit Agreements of the 2023 Form 10-K for additional information on the Registrants' credit facilities.

Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed in the first quarter of 2024 and was bifurcated into two tranches of $350 million and $150 million on March 14, 2024. The agreements will expire on March 14, 2025. Pursuant to the loan agreements, loans made thereunder bear interest at a variable rate equal to SOFR plus 1.05% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.

On May 9, 2023, ComEd entered into a 364-day term loan agreement for $400 million with a variable rate equal to SOFR plus 1.00% and an expiration date of May 7, 2024. On May 1, 2024, ComEd entered into an agreement to extend the loan through the expiration date of June 28, 2024. The original proceeds from the loan were used to repay outstanding commercial paper obligations and for general corporate purposes. The balance of the loan was repaid on May 16, 2024. Refer to the Issuance of Long-term Debt Table below for further information.

82

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Debt and Credit Agreements

Long-Term Debt

Issuance of Long-Term Debt

During the nine months ended September 30, 2024, the following long-term debt was issued:

Company	Type	Interest Rate	Maturity	Amount	Use of Proceeds
Exelon	Notes	5.15%	March 15, 2029	$650	Repay Exelon SMBC Term Loan, outstanding commercial paper, and for general corporate purposes.
Exelon	Notes	5.45%	March 15, 2034	$650	Repay Exelon SMBC Term Loan, outstanding commercial paper, and for general corporate purposes.
Exelon	Notes	5.60%	March 15, 2053	$400	Repay Exelon SMBC Term Loan, outstanding commercial paper, and for general corporate purposes.
ComEd	First Mortgage Bonds	5.30%	June 1, 2034	$400	Repay existing indebtedness, repay outstanding commercial paper obligations, and to fund other general corporate purposes.
ComEd	First Mortgage Bonds	5.65%	June 1, 2054	$400	Repay existing indebtedness, repay outstanding commercial paper obligations, and to fund other general corporate purposes.
PECO	First Mortgage Bonds	5.25%	September 15, 2054	$575	Refinance outstanding commercial paper and for general corporate purposes
BGE	Notes	5.30%	June 1, 2034	$400	Repay outstanding commercial paper obligations and for general corporate purposes
BGE	Notes	5.65%	June 1, 2054	$400	Repay outstanding commercial paper obligations and for general corporate purposes
Pepco	First Mortgage Bonds	5.20%	March 15, 2034	$375	Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.
Pepco	First Mortgage Bonds	5.50%	March 15, 2054	$300	Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.
DPL	First Mortgage Bonds	5.24%	March 20, 2034	$100	Repay existing indebtedness and for general corporate purposes.
DPL	First Mortgage Bonds	5.55%	March 20, 2054	$75	Repay existing indebtedness and for general corporate purposes.
ACE	First Mortgage Bonds	5.55%	March 20, 2054	$75	Repay existing indebtedness and for general corporate purposes.
ACE	First Mortgage Bonds	5.29%	August 28, 2034	$75	Repay existing indebtedness and for general corporate purposes.
ACE	First Mortgage Bonds	5.49%	August 28, 2039	$100	Repay existing indebtedness and for general corporate purposes.

Debt Covenants

As of September 30, 2024, the Registrants are in compliance with debt covenants.

83

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities

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

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

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

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

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

Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of the 2023 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, 2024 and December 31, 2023. 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, 2024										December 31, 2023
	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	$	44,655	$	—	$	37,642	$	3,937	$	41,579	$	41,095	$	—	$	33,804	$	3,442	$	37,246
ComEd	12,028		—		10,957		—		10,957		11,486		—		10,210		—		10,210
PECO	5,703		—		5,156		—		5,156		5,134		—		4,562		—		4,562
BGE	5,395		—		5,021		—		5,021		4,602		—		4,145		—		4,145
PHI	9,135		—		4,333		3,937		8,270		8,648		—		4,160		3,442		7,602
Pepco	4,362		—		2,638		1,634		4,272		4,096		—		2,311		1,600		3,911
DPL	2,221		—		667		1,329		1,996		2,080		—		694		1,134		1,828
ACE	1,935		—		809		974		1,783		1,833		—		939		708		1,647
Long-Term Debt to Financing Trusts
Exelon	$	390	$	—	$	—	$	409	$	409	$	390	$	—	$	—	$	390	$	390
ComEd	206		—		—		215		215		205		—		—		208		208
PECO	184		—		—		194		194		184		—		—		182		182

__________

(a)Includes unamortized debt issuance costs, unamortized debt discount and premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are not fair valued. Refer to Note 16 — Debt and Credit Agreements of the 2023 Form 10-K for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 10 — Leases of the 2023 Form 10-K for finance lease liabilities.

84

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities

Recurring Fair Value Measurements

The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at September 30, 2024 and December 31, 2023. Exelon and the Utility Registrants have immaterial and no financial assets or liabilities measured using the NAV practical expedient, respectively:

Exelon

	At September 30, 2024						At December 31, 2023
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	861	$	—	$	—	$	861	$	618	$	—	$	—	$	618
Rabbi trust investments
Cash equivalents	93		—		—		93		67		—		—		67
Mutual funds	62		—		—		62		53		—		—		53
Fixed income	—		7		—		7		—		7		—		7
Life insurance contracts	—		70		22		92		—		61		43		104
Rabbi trust investments subtotal	155		77		22		254		120		68		43		231
Interest rate derivative assets
Derivatives designated as hedging instruments	—		—		—		—		—		11		—		11
Economic hedges	—		—		—		—		—		1		—		1
Interest rate derivative assets subtotal	—		—		—		—		—		12		—		12
Total assets	1,016		77		22		1,115		738		80		43		861
Liabilities
Commodity derivative liabilities	—		—		(165)		(165)		—		—		(133)		(133)
Interest rate derivative liabilities
Derivatives designated as hedging instruments	—		(39)		—		(39)		—		(24)		—		(24)
Economic hedges	—		—		—		—		—		(22)		—		(22)
Interest rate derivative liabilities subtotal	—		(39)		—		(39)		—		(46)		—		(46)
Deferred compensation obligation	—		(75)		—		(75)		—		(75)		—		(75)
Total liabilities	—		(114)		(165)		(279)		—		(121)		(133)		(254)
Total net assets (liabilities)	$	1,016	$	(37)	$	(143)	$	836	$	738	$	(41)	$	(90)	$	607

__________    

(a)Exelon excludes cash of $205 million and $334 million at September 30, 2024 and December 31, 2023, respectively, and restricted cash of $167 million and $149 million at September 30, 2024 and December 31, 2023, respectively, and includes long-term restricted cash of $65 million and $174 million at September 30, 2024 and December 31, 2023, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets.

85

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities

ComEd, PECO, and BGE

	ComEd								PECO								BGE
At September 30, 2024	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	403	$	—	$	—	$	403	$	18	$	—	$	—	$	18	$	313	$	—	$	—	$	313
Rabbi trust investments
Mutual funds	—		—		—		—		11		—		—		11		10		—		—		10
Life insurance contracts	—		—		—		—		—		21		—		21		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		11		21		—		32		10		—		—		10
Total assets	403		—		—		403		29		21		—		50		323		—		—		323
Liabilities
Commodity derivative liabilities(b)	—		—		(165)		(165)		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		(9)		—		(9)		—		(7)		—		(7)		—		(4)		—		(4)
Total liabilities	—		(9)		(165)		(174)		—		(7)		—		(7)		—		(4)		—		(4)
Total net assets (liabilities)	$	403	$	(9)	$	(165)	$	229	$	29	$	14	$	—	$	43	$	323	$	(4)	$	—	$	319

	ComEd								PECO								BGE
At December 31, 2023	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	453	$	—	$	—	$	453	$	9	$	—	$	—	$	9	$	—	$	—	$	—	$	—
Rabbi trust investments
Mutual funds	—		—		—		—		9		—		—		9		9		—		—		9
Life insurance contracts	—		—		—		—		—		18		—		18		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		9		18		—		27		9		—		—		9
Total assets	453		—		—		453		18		18		—		36		9		—		—		9
Liabilities
Commodity derivative liabilities(b)	—		—		(133)		(133)		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		(8)		—		(8)		—		(8)		—		(8)		—		(4)		—		(4)
Total liabilities	—		(8)		(133)		(141)		—		(8)		—		(8)		—		(4)		—		(4)
Total net assets (liabilities)	$	453	$	(8)	$	(133)	$	312	$	18	$	10	$	—	$	28	$	9	$	(4)	$	—	$	5

__________

(a)ComEd excludes cash of $84 million and $86 million at September 30, 2024 and December 31, 2023, respectively, and restricted cash of $167 million and $147 million at September 30, 2024 and December 31, 2023, respectively. Additionally, ComEd includes long-term restricted cash of $65 million and $174 million at September 30, 2024 and December 31, 2023, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO excludes cash of $19 million and $42 million at September 30, 2024 and December 31, 2023, respectively. BGE excludes

86

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities

cash of $18 million and $47 million at September 30, 2024 and December 31, 2023, respectively, and restricted cash of zero and $1 million at September 30, 2024 and December 31, 2023, respectively.

(b)The Level 3 balance consists of the current and noncurrent liability of $25 million and $140 million, respectively, at September 30, 2024 and $27 million and $106 million, respectively, at December 31, 2023 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

87

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL, and ACE

	At September 30, 2024								At December 31, 2023
PHI	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	74	$	—	$	—	$	74	$	107	$	—	$	—	$	107
Rabbi trust investments
Cash equivalents	90		—		—		90		64		—		—		64
Mutual funds	9		—		—		9		9		—		—		9
Fixed income	—		7		—		7		—		7		—		7
Life insurance contracts	—		23		21		44		—		21		41		62
Rabbi trust investments subtotal	99		30		21		150		73		28		41		142
Total assets	173		30		21		224		180		28		41		249
Liabilities
Deferred compensation obligation	—		(11)		—		(11)		—		(13)		—		(13)
Total liabilities	—		(11)		—		(11)		—		(13)		—		(13)
Total net assets	$	173	$	19	$	21	$	213	$	180	$	15	$	41	$	236

	Pepco								DPL								ACE
At September 30, 2024	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	21	$	—	$	—	$	21	$	3	$	—	$	—	$	3	$	—	$	—	$	—	$	—
Rabbi trust investments
Cash equivalents	90		—		—		90		—		—		—		—		—		—		—		—
Life insurance contracts	—		23		21		44		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	90		23		21		134		—		—		—		—		—		—		—		—
Total assets	111		23		21		155		3		—		—		3		—		—		—		—
Liabilities
Deferred compensation obligation	—		(1)		—		(1)		—		—		—		—		—		—		—		—
Total liabilities	—		(1)		—		(1)		—		—		—		—		—		—		—		—
Total net assets	$	111	$	22	$	21	$	154	$	3	$	—	$	—	$	3	$	—	$	—	$	—	$	—

88

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities

	Pepco								DPL								ACE
At December 31, 2023	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	23	$	—	$	—	$	23	$	1	$	—	$	—	$	1	$	—	$	—	$	—	$	—
Rabbi trust investments
Cash equivalents	63		—		—		63		—		—		—		—		—		—		—		—
Life insurance contracts	—		21		41		62		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	63		21		41		125		—		—		—		—		—		—		—		—
Total assets	86		21		41		148		1		—		—		1		—		—		—		—
Liabilities
Deferred compensation obligation	—		(1)		—		(1)		—		—		—		—		—		—		—		—
Total liabilities	—		(1)		—		(1)		—		—		—		—		—		—		—		—
Total net assets	$	86	$	20	$	41	$	147	$	1	$	—	$	—	$	1	$	—	$	—	$	—	$	—

__________

(a)PHI excludes cash of $48 million and $96 million at September 30, 2024 and December 31, 2023, respectively, and restricted cash of zero and $1 million at September 30, 2024 and December 31, 2023, respectively. Pepco excludes cash of $19 million and $48 million at September 30, 2024 and December 31, 2023, respectively, and restricted cash of zero and $1 million at September 30, 2024 and December 31, 2023, respectively. DPL excludes cash of $7 million and $15 million at September 30, 2024 and December 31, 2023, respectively. ACE excludes cash of $17 million and $21 million at September 30, 2024 and December 31, 2023, 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, 2024 and 2023:

	Exelon		ComEd			PHI and Pepco
Three Months Ended September 30, 2024	Total		Commodity Derivatives			Life Insurance Contracts
Balance at June 30, 2024	$	(116)	$	(139)		$	22
Total realized / unrealized gains (losses)
Included in net income(a)	—		—			—
Included in regulatory assets/liabilities	(26)		(26)		(b)	—
Purchases, sales, and settlements
Settlements	(1)		—			(1)
Balance at September 30, 2024	$	(143)	$	(165)	(c)	$	21
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2024	$	—	$	—		$	—

89

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities

	Exelon		ComEd			PHI and Pepco
Three Months Ended September 30, 2023	Total		Commodity Derivatives			Life Insurance Contracts
Balance at June 30, 2023	$	(91)	$	(133)		$	42
Total realized / unrealized gains (losses)
Included in net income(a)	—		—			(2)
Included in regulatory assets/liabilities	(1)		(1)		(b)	—
Balance at September 30, 2023	$	(92)	$	(134)		$	40
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2023	$	—	$	—		$	(2)

	Exelon		ComEd			PHI and Pepco
Nine Months Ended September 30, 2024	Total		Commodity Derivatives			Life Insurance Contracts
Balance at December 31, 2023	$	(90)	$	(133)		$	41
Total realized / unrealized gains (losses)
Included in net income(a)	1		—			2
Included in regulatory assets/liabilities	(32)		(32)		(b)	—
Purchases, sales, and settlements
Settlements	(22)		—			(22)
Balance at September 30, 2024	$	(143)	$	(165)	(c)	$	21
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2024	$	2	$	—		$	2

	Exelon		ComEd			PHI and Pepco
Nine Months Ended September 30, 2023	Total		Commodity Derivatives			Life Insurance Contracts
Balance at December 31, 2022	$	(44)	$	(84)		$	40
Total realized / unrealized gains (losses)
Included in net income(a)	2		—			—
Included in regulatory assets/liabilities	(50)		(50)		(b)	—
Balance at September 30, 2023	$	(92)	$	(134)		$	40
The amount of total gains included in income attributed to the change in unrealized gain related to assets and liabilities at September 30, 2023	$	2	$	—		$	—

__________

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

(b)Includes $31 million of decreases in fair value and an increase for realized gains due to settlements of $5 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2024. Includes $5 million of decreases in fair value and an increase for realized gains due to settlements of $4 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2023. Includes $60 million of decreases in fair value and an increase for realized gains due to settlements of $28 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2024. Includes $73 million of decreases in fair value and an increase for realized gains due to settlements of $23 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2023.

(c)The balance of the current and noncurrent asset was effectively zero as of September 30, 2024. The balance consists of a current and noncurrent liability of $25 million and $140 million, respectively, as of September 30, 2024.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Fair Value of Financial Assets and Liabilities

Commodity Derivatives (Exelon and ComEd)

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

Type of trade	Fair Value at September 30, 2024		Fair Value at December 31, 2023		Valuation Technique	Unobservable Input	2024 Range & Arithmetic Average				2023 Range & Arithmetic Average
Commodity derivatives	$	(165)	$	(133)	Discounted Cash Flow	Forward power price(a)	$22.68	-	$55.35	$36.45	$30.27	-	$73.71	$43.35

________

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

11. Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 18 — Commitments and Contingencies of the 2023 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, 2024:

Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments(a)	30		27		24		2		1

__________

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

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Commitments and Contingencies

Commercial Commitments (All Registrants). The Registrants’ commercial commitments at September 30, 2024, representing commitments potentially triggered by future events, were as follows:

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Commitments and Contingencies

			Expiration within
	Total		2024		2025		2026		2027		2028		2029 and beyond
Exelon
Letters of credit(a)	$	54	$	11	$	43	$	—	$	—	$	—	$	—
Surety bonds(b)	195		86		107		—		2		—		—
Financing trust guarantees(c)	378		—		—		—		—		78		300
Guaranteed lease residual values(d)	26		—		2		5		4		6		9
Total commercial commitments	$	653	$	97	$	152	$	5	$	6	$	84	$	309
ComEd
Letters of credit(a)	$	17	$	4	$	13	$	—	$	—	$	—	$	—
Surety bonds(b)	36		5		29		—		2		—		—
Financing trust guarantees(c)	200		—		—		—		—		—		200
Total commercial commitments	$	253	$	9	$	42	$	—	$	2	$	—	$	200
PECO
Letters of credit(a)	$	4	$	—	$	4	$	—	$	—	$	—	$	—
Surety bonds(b)	2		—		2		—		—		—		—
Financing trust guarantees(c)	178		—		—		—		—		78		100
Total commercial commitments	$	184	$	—	$	6	$	—	$	—	$	78	$	100
BGE
Letters of credit(a)	$	27	$	6	$	21	$	—	$	—	$	—	$	—
Surety bonds(b)	3		1		2		—		—		—		—
Total commercial commitments	$	30	$	7	$	23	$	—	$	—	$	—	$	—
PHI
Letters of credit(a)	$	3	$	—	$	3	$	—	$	—	$	—	$	—
Surety bonds(b)	97		76		21		—		—		—		—
Guaranteed lease residual values(d)	26		—		2		5		4		6		9
Total commercial commitments	$	126	$	76	$	26	$	5	$	4	$	6	$	9
Pepco
Letters of credit(a)	$	2	$	—	$	2	$	—	$	—	$	—	$	—
Surety bonds(b)	85		71		14		—		—		—		—
Guaranteed lease residual values(d)	9		—		1		2		1		2		3
Total commercial commitments	$	96	$	71	$	17	$	2	$	1	$	2	$	3
DPL
Letters of credit(a)	$	1	$	—	$	1	$	—	$	—	$	—	$	—
Surety bonds(b)	7		3		4		—		—		—		—
Guaranteed lease residual values(d)	10		—		1		2		2		2		3
Total commercial commitments	$	18	$	3	$	6	$	2	$	2	$	2	$	3
ACE
Surety bonds(b)	$	5	$	2	$	3	$	—	$	—	$	—	$	—
Guaranteed lease residual values(d)	7		—		—		1		1		2		3
Total commercial commitments	$	12	$	2	$	3	$	1	$	1	$	2	$	3

__________

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Commitments and Contingencies

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

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

(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 $60 million guaranteed by Exelon and PHI, of which $21 million, $22 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 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2031.

•PECO has 6 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2027.

•BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2025.

•DPL has 1 site that is currently under study and the required cost at the site is not expected to be material.

The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

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

During the third quarter of 2024, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The study resulted in increases of $13 million and $4 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 and changes in remediation plans.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Commitments and Contingencies

At September 30, 2024 and December 31, 2023, 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, 2024				December 31, 2023
	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	$	410	$	328	$	428	$	338
ComEd	290		289		303		302
PECO	31		28		27		25
BGE	14		11		14		11
PHI	75		—		81		—
Pepco	73		—		79		—
DPL	1		—		1		—
ACE	1		—		1		—

Benning Road Site (Exelon, PHI, and Pepco). In September 2010, PHI received a letter from the EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site, which is owned by Pepco, was formerly the location of an electric generating facility owned by Pepco subsidiary, Pepco Energy Services (PES), which became a part of Generation following the 2016 merger between PHI and Exelon. This generating facility was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco Entities to conduct a Remedial Investigation and Feasibility Study (RI/FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS is to define the nature and extent of contamination from the Benning Road site and to evaluate remedial alternatives.

Pursuant to an internal agreement between the Pepco Entities, since 2013, Pepco has performed the work required by the Consent Decree and has been reimbursed for that work by an agreed upon allocation of costs between the Pepco Entities. In September 2019, the Pepco Entities issued a draft “final” RI report which the DOEE approved on February 3, 2020. The Pepco Entities are completing a FS to evaluate possible remedial alternatives for submission to the DOEE. 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 15, 2024, and the waterside FS is scheduled to be complete and approved by the DOEE by the end of the fourth quarter of 2024. Following the completion of each FS, the DOEE will issue a Proposed Plan for public comment and then issue a Record of Decision (ROD) identifying the remedial actions determined to be necessary for the area in question. On October 3, 2023, 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.

As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Generation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. Exelon, PHI, and Pepco have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.

Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by the Pepco Entities, the DOEE and NPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The riverwide RI incorporated the results

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Commitments and Contingencies

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. On October 3, 2023, 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. The funds will be 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 potentially responsible parties. 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 very early stage of the NRD process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process.

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

Buzzard Point Site (Exelon, PHI, and Pepco). On December 8, 2022, Pepco received a letter from the D.C. OAG, alleging wholly past violations of the District's stormwater discharge and waste disposal requirements related to operations at the Buzzard Point facility, a 9-acre parcel of waterfront property in Washington, D.C. occupied by an active substation and former steam plant building. The letter also alleged wholly past violations by Pepco of stormwater discharge requirements related to its district-wide system of underground vaults. On October 3, 2023, 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 court signed and entered the Consent Order, and it became effective on February 2, 2024. Exelon, PHI, and Pepco have accrued a liability for the penalty payments and for the projected costs for the required environmental assessments and remediation. Pepco has concluded that incremental exposure is reasonably possible, but the range of loss cannot be reasonably estimated beyond the amounts included in the table above.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Commitments and Contingencies

Litigation and Regulatory Matters

DPA and Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation, 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.

On September 28, 2023, Exelon and ComEd reached a settlement with the SEC, concluding and resolving in its entirety the SEC investigation, which related to the conduct identified in the DPA that was entered into by ComEd in July 2020 and successfully exited in July 2023. Under the terms of the settlement, Exelon has agreed to pay a civil penalty of $46.2 million and Exelon and ComEd have agreed to cease and desist from committing or causing any violations and any future violations of specified provisions of the federal securities laws and rules promulgated thereunder. Exelon recorded an accrual for the full amount of the penalty in the second quarter of 2023, which was reflected in Operating and maintenance expense within Exelon's Consolidated Statements of Operations and Comprehensive Income and in Accrued expenses on the Consolidated Balance Sheets. Exelon paid the civil penalty in full on October 4, 2023.

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

•Four putative class action lawsuits against ComEd and Exelon were filed in federal court on behalf of ComEd customers in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. The court granted ComEd and Exelon's motion to dismiss these actions in 2021 and that dismissal was affirmed on appeal in 2022. Plaintiffs have no further appeal rights and therefore the dismissal is final.

•Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. The cases were consolidated into a single action in October of 2020. In 2021, the plaintiffs that filed the class action lawsuits in federal court (“federal plaintiffs”) refiled their dismissed state law claims in state court. ComEd and Exelon moved to dismiss both lawsuits. The court dismissed the original consolidated state court lawsuit in December 2021 and dismissed the federal plaintiffs’ refiled claims in February 2022. Both sets of plaintiffs appealed their dismissals, and the appeals were consolidated in March 2022. On September 8, 2023, the appellate court affirmed the dismissals. On December 22, 2023, plaintiffs collectively filed a petition for leave to appeal to the Illinois Supreme Court, which ComEd and Exelon responded to on January 12, 2024. On March 27, 2024, the Illinois Supreme Court denied plaintiffs' petition for leave to appeal. The dismissal of this action is final.

•On November 3, 2022, a plaintiff filed a putative class action complaint in Lake County, Illinois Circuit Court against ComEd and Exelon for unjust enrichment and deceptive business practices in connection with the conduct giving rise to the DPA. Plaintiff seeks an accounting and disgorgement of any benefits ComEd allegedly obtained from said conduct. ComEd and Exelon filed a motion to dismiss the Complaint on February 3, 2023. On June 16, 2023, the court granted ComEd and Exelon's motion to dismiss the action with prejudice. Plaintiff filed its notice of appeal of that dismissal on July 17, 2023. On April 12, 2024, the appellate court issued its decision affirming dismissal of the action. On June 3, 2024, plaintiff filed a petition for leave to appeal the dismissal to the Illinois Supreme Court, which is a discretionary appeal. ComEd and Exelon filed its response to that petition on July 19, 2024. On September 25, 2024, the Illinois Supreme Court denied plaintiff’s petition for leave to appeal. The dismissal of this action is now final.

•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Commitments and Contingencies

related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. The court denied the motion in April 2021. Following mediation, the parties reached a settlement of the lawsuit, under which defendants agreed to pay plaintiffs $173 million. On May 26, 2023, plaintiffs filed a motion for preliminary approval of the settlement, which the court granted on June 9, 2023. The court granted final settlement approval on September 7, 2023. The settlement was fully covered by insurance and has been paid in full.    

•Several shareholders have sent letters to the Exelon Board of Directors since 2020 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (SLC) consisting of disinterested and independent parties to investigate and address these shareholders’ allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC’s investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. Since that date, multiple parties have filed separate derivative lawsuits that were subsequently consolidated. On October 12, 2021, the parties filed an agreed motion to stay the litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The stay was extended several times. Through mediation efforts, a settlement of the derivative claims was reached by the SLC, the Independent Review Committee of the Board (which had been formed in the third quarter of 2022, to ensure the Board’s consideration of any SLC recommendations would be independent and objective), the Board, and certain of the derivative shareholders. On June 16, 2023, the SLC filed a motion for preliminary approval of the settlement, attaching the Stipulation and Agreement of Settlement (Stipulation), which contained the terms of the proposed settlement. The proposed settlement terms include but are not limited to: a payment of $40 million to Exelon by Exelon’s insurers of which $10 million constitutes the attorneys’ fee award to be paid to the Settling Shareholders’ counsel; various compliance and disclosure-related reforms; and certain changes in Board and Committee composition. On June 30, 2023, the court granted the non-settling shareholders’ request for limited discovery into the settlement. Following that discovery, on October 26, 2023, the SLC filed its renewed motion for preliminary approval with supporting submissions filed by the Independent Review Committee, Exelon, and the Settling Shareholders on that same day. The parties briefing on preliminary approval was completed on January 18, 2024. On September 20, 2024, the court denied without prejudice the SLC’s motion for preliminary approval. The court’s order provides that if the SLC can substantiate or otherwise revise the attorneys’ fees aspect of the settlement, then the SLC can renew its motion for preliminary approval by October 21, 2024. Otherwise, the court directed the parties to file a joint status report by October 30, 2024, proposing next steps to advance the case. 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.

In August 2022, the ICC concluded its investigation initiated on August 12, 2021 into rate impacts of conduct admitted in the DPA, including the costs recovered from customers related to the DPA and Exelon's funding of the fine paid by ComEd. On August 17, 2022, the ICC issued its final order accepting ComEd's voluntary customer refund offer of approximately $38 million (of which about $31 million was ICC jurisdictional; the remaining balance was FERC jurisdictional) that resolved the question of whether customer funds were used for DPA related activities. The customer refund included the cost of every individual or entity that was either (i) identified in the DPA or (ii) identified by ComEd as an associate of the former Speaker of the Illinois House of Representatives in the ICC proceeding. The ICC’s DPA investigation is now closed. The ICC jurisdictional refund was made to customers during the April 2023 billing cycle, as required by the ICC. The FERC jurisdictional refund was completed as of May 2024 as part of ComEd's transmission formula rate update proceeding, submitted on May 12, 2023. The customer refund was not recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon.

General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The Registrants are also from time to time subject to audits and investigations by the FERC and other regulators. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex

98

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Commitments and Contingencies

judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

12. Shareholders' Equity (Exelon)

At-the-Market Program

On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of Common stock under the Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the Equity Distribution Agreement. In the fourth quarter 2023, Exelon issued approximately 3.6 million shares of Common stock at an average gross price of $39.58 per share. In the third quarter 2024, Exelon issued approximately 4.0 million shares of Common Stock at an average gross price of $37.60 per share. The net proceeds from the fourth quarter 2023 and third quarter 2024 issuances were $140 million and $147 million, respectively, which were used for general corporate purposes. As of September 30, 2024, $708 million of Common stock remained available for sale pursuant to the ATM program.

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

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

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

Three Months Ended September 30, 2023	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Total
Balance at June 30, 2023	$	17	$	(647)	$	(630)
OCI before reclassifications	22		(3)		19
Amounts reclassified from AOCI	(1)		16		15
Net current-period OCI	21		13		34
Balance at September 30, 2023	$	38	$	(634)	$	(596)

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

99

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Changes in Accumulated Other Comprehensive Income

Nine Months Ended September 30, 2023	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Total
Balance at December 31, 2022	$	2	$	(640)	$	(638)
OCI before reclassifications	37		(16)		21
Amounts reclassified from AOCI	(1)		22		21
Net current-period OCI	$	36	$	6	$	42
Balance at September 30, 2023	$	38	$	(634)	$	(596)

__________

(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits of the 2023 Form 10-K and Note 7 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

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,
	2024		2023		2024		2023
Pension and non-pension postretirement benefit plans:
Actuarial losses reclassified to periodic benefit cost	$	(2)	$	(5)	$	(6)	$	(7)
Pension and non-pension postretirement benefit plans valuation adjustments	—		1		8		5
Unrealized gains on cash flow hedges	10		(7)		—		(11)

14. Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

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

100

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Supplemental Financial Information

	Taxes other than income taxes
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2024
Utility taxes(a)	$	248	$	80	$	51	$	25	$	92	$	84	$	7	$	1
Property	111		7		5		57		41		28		12		1
Payroll	33		9		4		5		7		2		1		—
Three Months Ended September 30, 2023
Utility taxes(a)	$	244	$	82	$	50	$	23	$	89	$	82	$	6	$	1
Property	104		9		4		53		38		25		12		1
Payroll	31		8		4		5		7		2		1		1
Nine Months Ended September 30, 2024
Utility taxes(a)	$	695	$	229	$	134	$	78	$	254	$	230	$	21	$	3
Property	323		25		14		164		119		81		35		2
Payroll	100		27		13		14		22		6		3		2
Nine Months Ended September 30, 2023
Utility taxes(a)	$	665	$	228	$	128	$	73	$	236	$	213	$	20	$	3
Property	300		27		12		153		108		73		34		1
Payroll	93		22		13		14		22		5		3		3

_________

(a)The Registrants' utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

	Other, net
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2024
AFUDC — Equity	$	38	$	13	$	7	$	5	$	12	$	8	$	3	$	1
Non-service net periodic benefit cost	(13)		—		—		—		—		—		—		—
Three Months Ended September 30, 2023
AFUDC — Equity	$	40	$	7	$	10	$	4	$	19	$	15	$	3	$	1
Non-service net periodic benefit cost	(18)		—		—		—		—		—		—		—
Nine Months Ended September 30, 2024
AFUDC — Equity	$	116	$	32	$	24	$	18	$	42	$	32	$	9	$	1
Non-service net periodic benefit cost	(29)		—		—		—		—		—		—		—
Nine Months Ended September 30, 2023
AFUDC — Equity	$	113	$	25	$	22	$	11	$	55	$	42	$	7	$	6
Non-service net periodic benefit cost	(18)		—		—		—		—		—		—		—

Supplemental Cash Flow Information

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

101

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Supplemental Financial Information

	Depreciation, amortization, and accretion
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2024
Property, plant, and equipment(a)	$	2,168	$	869	$	308	$	369	$	581	$	249	$	162	$	158
Amortization of regulatory assets and liabilities, net(a)	507		255		10		105		135		58		21		56
Amortization of intangible assets, net(a)	6		—		—		—		—		—		—		—
ARO accretion(b)	2		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	2,683	$	1,124	$	318	$	474	$	716	$	307	$	183	$	214
Nine Months Ended September 30, 2023
Property, plant, and equipment(a)	$	2,073	$	815	$	287	$	381	$	550	$	232	$	155	$	145
Amortization of regulatory assets and liabilities, net(a)	537		230		10		106		191		97		27		67
Amortization of intangible assets, net(a)	6		—		—		—		—		—		—		—
ARO accretion(b)	—		—		—		—		—		—		—		—
Total depreciation and amortization	$	2,616	$	1,045	$	297	$	487	$	741	$	329	$	182	$	212

__________

(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.

	Other non-cash operating activities
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2024
Pension and OPEB costs (benefit)	$	181	$	53	$	(1)	$	45	$	71	$	24	$	11	$	10
Allowance for credit losses	170		17		79		23		51		25		7		19
True-up adjustments to decoupling mechanisms and formula rates(a)	49		100		(3)		(28)		(20)		(42)		7		15
Amortization of operating ROU asset	28		—		—		5		19		4		6		2
AFUDC — Equity	(116)		(32)		(24)		(18)		(42)		(32)		(9)		(1)
Nine Months Ended September 30, 2023
Pension and OPEB costs (benefit)	$	152	$	19	$	(10)	$	41	$	74	$	26	$	13	$	10
Allowance for credit losses	86		4		31		4		47		27		9		11
True-up adjustments to decoupling mechanisms and formula rates(a)	(522)		(405)		(1)		(47)		(69)		(28)		(15)		(26)
Amortization of operating ROU asset	29		2		—		4		21		5		6		2
Change in environmental liabilities	37		—		—		—		37		37		—		—
AFUDC — Equity	(113)		(25)		(22)		(11)		(55)		(42)		(7)		(6)

__________

(a)For ComEd, reflects the true-up adjustments in Regulatory assets and liabilities associated with its distribution, energy efficiency, distributed generation, and transmission formula rates. For PECO, reflects the change in Regulatory assets and liabilities associated with its transmission formula rates. For BGE, Pepco, DPL, and ACE, reflects the change in Regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 3 — Regulatory Matters of the 2023 Form 10-K for additional information.

102

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Supplemental Financial Information

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

	Cash, cash equivalents, and restricted cash
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at September 30, 2024
Cash and cash equivalents	$	616	$	109	$	28	$	330	$	100	$	20	$	8	$	17
Restricted cash and cash equivalents	552		481		9		—		22		20		2		—
Restricted cash included in Other deferred debits and other assets	65		65		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,233	$	655	$	37	$	330	$	122	$	40	$	10	$	17
Balance at December 31, 2023
Cash and cash equivalents	$	445	$	110	$	42	$	47	$	180	$	48	$	16	$	21
Restricted cash and cash equivalents	482		402		9		1		24		24		—		—
Restricted cash included in Other deferred debits and other assets	174		174		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,101	$	686	$	51	$	48	$	204	$	72	$	16	$	21
Balance at September 30, 2023
Cash and cash equivalents	$	300	$	79	$	43	$	15	$	121	$	31	$	5	$	14
Restricted cash and cash equivalents	435		360		9		1		25		25		1		—
Restricted cash included in Other deferred debits and other assets	212		212		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	947	$	651	$	52	$	16	$	146	$	56	$	6	$	14
Balance at December 31, 2022
Cash and cash equivalents	$	407	$	67	$	59	$	43	$	198	$	45	$	31	$	72
Restricted cash and cash equivalents	566		327		9		24		175		54		121		—
Restricted cash included in Other deferred debits and other assets	117		117		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,090	$	511	$	68	$	67	$	373	$	99	$	152	$	72

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2023 Form 10-K.

Supplemental Balance Sheet Information

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

103

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Supplemental Financial Information

	Accrued expenses
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at September 30, 2024
Compensation-related accruals(a)	$	546	$	165	$	68	$	70	$	100	$	28	$	19	$	12
Taxes accrued	203		89		19		28		101		89		15		5
Interest accrued	431		92		55		74		85		38		27		18
Balance at December 31, 2023
Compensation-related accruals(a)	$	661	$	206	$	87	$	81	$	107	$	27	$	17	$	12
Taxes accrued	221		204		96		75		137		116		30		10
Interest accrued	414		148		49		44		72		38		13		15

__________

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

Book Overdrafts (BGE)

Book overdrafts representing outstanding checks in excess of funds on deposit are included in Other current liabilities on the Registrants' Consolidated Balance Sheet. The balance of BGE's book overdrafts was $48 million and $9 million as of September 30, 2024 and December 31, 2023, respectively.

15. Related Party Transactions (All Registrants)

Service Company Costs for Corporate Support

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

104

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — 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,
	2024		2023		2024		2023		2024		2023		2024		2023
Exelon
BSC									$	141	$	162	$	458	$	502
PHISCO									27		25		85		74
ComEd
BSC	$	102	$	92	$	306	$	263	55		71		189		230
PECO
BSC	61		55		180		160		23		29		81		89
BGE
BSC	61		58		182		166		25		23		74		69
PHI
BSC	46		50		145		135		38		39		114		114
PHISCO	—		—		—		—		27		24		85		73
Pepco
BSC	29		30		92		85		16		13		51		41
PHISCO	28		31		94		91		12		9		36		30
DPL
BSC	19		19		58		54		11		12		36		32
PHISCO	24		24		75		73		8		7		25		22
ACE
BSC	16		16		48		45		9		13		24		39
PHISCO	23		23		71		67		7		7		24		20

105

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Related Party Transactions

Current Receivables from/Payables to Affiliates

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

September 30, 2024

				Receivables from affiliates:
	Payables to affiliates:			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
ComEd					$	1		$	—		$	—		$	—		$	—		$	57		$	—		$	58		$	116
PECO		$	—					—			—			—						30			—			6			36
BGE		1			—						—			—			—			32			—			15			48
PHI		—			—			—			—			—			—			6			1			10			17
Pepco		—			—			—						—			—			17			13			1			31
DPL		—			—			—			—						—			10			10			1			21
ACE		—			—			—			—			—						8			10			1			19
Other		3			—			—			—			—			5			—			—						8
Total		$	4		$	1		$	—		$	—		$	—		$	5		$	160		$	34		$	92		$	296

December 31, 2023

				Receivables from affiliates:
	Payables to affiliates:			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
ComEd					$	—		$	—		$	—		$	—		$	—		$	64		$	—		$	8		$	72
PECO		$	—					—			—			—			—			36			—			3			39
BGE		—			—						—			—			—			33			—			2			35
PHI		—			—			—			—			—			—			5			—			10			15
Pepco		—			—			—						—			—			17			14			1			32
DPL		—			1			—			—						—			12			11			1			25
ACE		—			1			—			1			1						11			11			—			25
Other		3			—			—			1			—			3			1			—						8
Total		$	3		$	2		$	—		$	2		$	1		$	3		$	179		$	36		$	25		$	251

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, 2024						December 31, 2023
	Exelon		ComEd		PECO		Exelon		ComEd		PECO
ComEd Financing III	$	206	$	206	$	—	$	206	$	205	$	—
PECO Trust III	81		—		81		81		—		81
PECO Trust IV	103		—		103		103		—		103
Total	$	390	$	206	$	184	$	390	$	205	$	184

106

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 it's 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, 2024 compared to the same period in 2023. For additional information regarding the financial results for the three and nine months ended September 30, 2024 and 2023, see the discussions of Results of Operations by Registrant.

	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2024		2023				2024		2023
Exelon	$	707	$	700	$	7	$	1,813	$	1,711	$	102
ComEd	360		333		27		823		822		1
PECO	117		146		(29)		356		410		(54)
BGE	45		45		—		353		286		67
PHI	278		232		46		603		490		113
Pepco	140		120		20		323		249		74
DPL	55		43		12		156		128		28
ACE	83		71		12		133		122		11
Other(a)	(93)		(56)		(37)		(322)		(297)		(25)

__________

(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, 2024 Compared to Three Months Ended September 30, 2023. Net income attributable to common shareholders increased by $7 million and diluted earnings per average common share remained relatively consistent to the prior year at $0.70 primarily due to:

•Timing of distribution earnings at ComEd;

•Favorable impacts of rate increases at BGE and PHI;

•Higher return on regulatory assets at ComEd; and

•Lower storm costs at PHI.

The increases were partially offset by:

107

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

•Higher credit loss expense at PECO and BGE;

•Higher depreciation and amortization expense at PECO and BGE;

•Lower electric distribution earnings from lower allowed ROE and the absence of a return on the pension asset at ComEd; and

•Lower carrying cost recovery related to the CMC regulatory asset at ComEd.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net income attributable to common shareholders increased by $102 million and diluted earnings per average common share increased to $1.81 in 2024 from $1.72 in 2023 primarily due to:

•Favorable impacts of rate increases at BGE and PHI;

•Less unfavorable weather at PECO;

•Timing of distribution earnings at ComEd;

•Higher return on regulatory assets at ComEd;

•Favorable impacts of the multi-year plans including the recognition of the reconciliations at Pepco;

•Higher transmission peak load due to higher energy demand at ComEd; and

•Lower storm costs at PHI.

The increases were partially offset by:

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

•Higher credit loss expense at PECO, BGE, and PHI;

•Higher depreciation expense at PECO and PHI;

•Lower electric distribution earnings from lower allowed ROE and the absence of a return on the pension asset at ComEd;

•Higher storm costs at PECO and BGE; and

•Lower carrying cost recovery related to the CMC regulatory asset at ComEd.

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

108

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, 2024 compared to the same period in 2023:

	Three Months Ended September 30,
	2024				2023
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net income attributable to common shareholders	$	707	$	0.70	$	700	$	0.70
Mark-to-market impact of economic hedging activities (net of taxes of $4)	—		—		12		—
Asset retirement obligation (net of taxes of $0 and $1, respectively)	—		—		(1)		—
Separation costs (net of taxes of $5)(a)	—		—		14		0.01
Cost management charge (net of taxes of $0)(b)	1		—		—		—
Income tax-related adjustments (entire amount represents tax expense)(c)	—		—		(54)		(0.05)
Adjusted (non-GAAP) operating earnings	$	708	$	0.71	$	671	$	0.67

	Nine Months Ended September 30,
	2024				2023
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net income attributable to common shareholders	$	1,813	$	1.81	$	1,711	$	1.72
Mark-to-market impact of economic hedging activities (net of taxes of $0 and $4)	—		—		14		0.01
Change in environmental liabilities (net of taxes of $0 and $8, respectively)	(1)		—		29		0.03
Asset retirement obligation (net of taxes of $0 and $1, respectively)	—		—		(1)		—
SEC matter loss contingency (net of taxes of $0)	—		—		46		0.05
Change in FERC audit liability (net of taxes of $13 and $4, respectively)	42		0.04		11		0.01
Separation costs (net of taxes of $7)(a)	—		—		19		0.02
Cost management charge (net of taxes of $3)(b)	10		0.01		—		—
Income tax-related adjustments (entire amount represents tax expense)(c)	—		—		(54)		(0.05)
Adjusted (non-GAAP) operating earnings	$	1,865	$	1.86	$	1,774	$	1.78

__________

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 2024 and 2023 ranged from 24.0% to 29.0%.

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

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

(c)In 2023, reflects the adjustment to state deferred income taxes dues to changes in forecasted apportionment.

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Significant 2024 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 2024. 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	$	501	8.905%		December 14, 2023	January 1, 2024
			$	838	$	810	8.905%		April 18, 2024	May 1, 2024
	April 21, 2023	Electric	$	247	$	259	8.91%		November 30, 2023	January 1, 2024
BGE - Maryland	February 17, 2023	Electric	$	313	$	179	9.50	%	December 14, 2023	January 1, 2024
		Natural Gas	$	289	$	229	9.45	%
Pepco - Maryland	May 16, 2023 (amended February 23, 2024)	Electric	$	111	$	45	9.50	%	June 10, 2024	April 1, 2024
DPL - Maryland	May 19, 2022	Electric	$	38	$	29	9.60	%	December 14, 2022	January 1, 2023
DPL - Delaware	December 15, 2022 (amended September 29, 2023)	Electric	$	39	$	28	9.60	%	April 18, 2024	July 15, 2023
ACE - New Jersey	February 15, 2023 (amended August 21, 2023)	Electric	$	92	$	45	9.60	%	November 17, 2023	December 1, 2023

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Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Requested ROE		Expected Approval Timing
ComEd - Illinois	March 15, 2024 (amended August 13, 2024)	Electric	$	667	8.905%		December 2024
	April 26, 2024 (amended September 11, 2024)	Electric	$	624	9.89%		Fourth quarter of 2024
PECO - Pennsylvania	March 28, 2024	Electric	$	464	10.95%		Fourth quarter of 2024
		Natural Gas	$	111	11.15%
Pepco - District of Columbia	April 13, 2023 (amended February 27, 2024)	Electric	$	186	10.50	%	Fourth quarter of 2024
DPL - Delaware	September 20, 2024	Natural Gas	$	36	10.65	%	First quarter of 2026

Transmission Formula Rates

For 2024, the following total increases/(decreases) were included in the Utility Registrant's electric transmission formula rate updates. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Registrant	Initial Revenue Requirement Increase		Annual Reconciliation (Decrease) Increase		Total Revenue Requirement Increase		Allowed Return on Rate Base		Allowed ROE
ComEd	$	32	$	(12)	$	20	8.14	%	11.50	%
PECO	$	2	$	3	$	5	7.45	%	10.35	%
BGE	$	42	$	13	$	53	7.47	%	10.50	%
Pepco	$	58	$	15	$	73	7.62	%	10.50	%
DPL	$	7	$	17	$	24	7.23	%	10.50	%
ACE	$	14	$	18	$	32	7.11	%	10.50	%

ComEd's FERC Audit

The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extends back to January 1, 2017.

On July 27, 2023, FERC issued a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. On August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place.

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On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The final settlement is subject to FERC approval. The existing loss estimate is reflected in Exelon and ComEd's financial statements as of September 30, 2024.

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 2023 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 2023 Form 10-K, and Note 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.

Legislative and Regulatory Developments

Infrastructure Investment and Jobs Act

On November 15, 2021, President Biden signed the $1.2 trillion IIJA into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. Federal agencies are developing guidelines to implement spending programs under IIJA. The time needed to develop these guidelines will vary with some limited program applications opened as early as the first quarter of 2022. The Registrants continue to evaluate programs under the legislation and consider possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.

In March 2023, Exelon, ComEd, and PHI submitted three applications related to the Smart Grid Grants program under section 40107 of IIJA. These applications are focused on replacing existing Advanced Distribution Management Systems (ADMS) in support of distributed energy resources (DERs) and grid-edged technologies, strengthening interoperability and data architecture of systems in support of two-way power flows and accelerating advanced metering deployment in disadvantaged communities. In October 2023, ComEd’s project, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, was recommended by the Grid Deployment Office (GDO) for negotiation of a final award up to $50 million. This project will enable ComEd and its local partners to deploy the next generation of grid technologies that support the growth of solar and electric vehicles (EVs), while piloting new local workforce training initiatives to support job creation connected to the clean energy transition. The award negotiation process is complete and funding has been obligated.

In April 2023, ComEd, PECO, BGE, and PHI submitted seven applications related to the Grid Resilience Grants program under section 40101(c) of IIJA. These applications are broadly focused on improving grid resilience with an emphasis on disadvantaged communities, relief of capacity constraints and modernizing infrastructure, deployment of DER and microgrid technologies and providing improved resilience through storm hardening projects. In October 2023, PECO’s project, Creating a Resilient, Equitable, and Accessible Transformation in Energy for Greater Philadelphia (CREATE), was recommended by the GDO for negotiation of a final award up to $100 million. This project will support critical electric infrastructure investments to help reduce the impact of extreme weather and historic flooding on the Registrants' electric distribution system. The award negotiation process is complete and funding has been obligated.

The Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon operates in plus Washington D.C. under a program that will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the use of hydrogen as a clean energy carrier that can deliver or store energy. Applications for the three opportunities under this program were submitted in April 2023. In October 2023 the DOE announced it selected two of the projects for further negotiation: (1) the Mid-Atlantic Clean Hydrogen Hub (MACH2), which is being supported by PECO and PHI, and (2) the Midwest Alliance for Clean Hydrogen (MachH2), which is being supported by ComEd.

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In November 2023, the GDO announced up to $3.9 billion available through the second-round funding opportunity of the Grid Resilience and Innovation Partnerships (GRIP) Program for fiscal years 2024 and 2025. This funding opportunity focuses on projects that will improve electric transmission by increasing funding and advancing interconnection processes for faster build out of energy projects, create comprehensive solutions that link grid communications systems and operations to increase resilience and reduce power outages and threats, and deploy advanced technologies such as distributed energy resources and battery systems to provide essential grid services to ensure American communities across the country have access to affordable, reliable, clean electricity. In March 2024, Exelon, BGE, PHI, Pepco, DPL, and ACE submitted five applications for Topic Area 2 (Smart Grid Grants). These applications focus on improving resilience of the electric grid and deployment of technologies to enhance grid flexibility and deliver benefits to customers across the Exelon footprint.

In October 2024, Exelon’s project, Renewable-Aware Distribution Operations: Pioneering a cleaner future for all our communities, and BGE’s project, Baltimore Interconnection Readiness & Deployment of Storage (BIRDS), were recommended by the GDO for negotiation of a final award up to $100 million and $50 million, respectively. The Exelon project will deploy advanced Distribution Energy Resource Management System (DERMS) capabilities and pilot technology to increase the flexibility, efficiency, reliability, and resilience of its distribution network. BGE’s project will facilitate a programmatic approach to a flexible and decentralized energy distribution grid while setting an automated and digitized framework for unlocking future clean energy investments. The GDO has indicated the negotiation process is expected to take a minimum of 120 days.

PJM Regional Transmission Expansion

On July 11, 2024, BGE submitted an application to the MDPSC for a Certificate of Public Convenience and Necessity for certain overhead transmission system upgrades necessitated due to the planned retirement of the Brandon Shores Generating Station. The total estimated costs of all work by BGE directed by PJM in connection with the retirement of the Brandon Shores Generating Station is approximately $1.1 billion.

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, 2024, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2023. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2023 Form 10-K for further information.

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Results of Operations by Registrant

Results of Operations — ComEd

	Three Months Ended September 30,				(Unfavorable) Favorable Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2024		2023				2024		2023
Operating revenues	$	2,229	$	2,268	$	(39)	$	6,403	$	5,836	$	567
Operating expenses
Purchased power	835		896		61		2,504		2,068		(436)
Operating and maintenance	410		385		(25)		1,277		1,077		(200)
Depreciation and amortization	387		357		(30)		1,124		1,045		(79)
Taxes other than income taxes	99		100		1		287		282		(5)
Total operating expenses	1,731		1,738		7		5,192		4,472		(720)
Gain on sales of assets	—		—		—		5		—		5
Operating income	498		530		(32)		1,216		1,364		(148)
Other income and (deductions)
Interest expense, net	(128)		(119)		(9)		(374)		(357)		(17)
Other, net	26		16		10		66		50		16
Total other income and (deductions)	(102)		(103)		1		(308)		(307)		(1)
Income before income taxes	396		427		(31)		908		1,057		(149)
Income taxes	36		94		58		85		235		150
Net income	$	360	$	333	$	27	$	823	$	822	$	1

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net income increased by $27 million as compared to the same period in 2023, primarily due to timing of distribution earnings, higher distribution rate base, and higher return on regulatory assets. These were partially offset by a lower allowed distributions ROE, the absence of a return on the pension asset within distribution earnings, and lower carrying cost recovery related to the CMC regulatory asset.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net income increased by $1 million as compared to the same period in 2023, primarily due to timing of distribution earnings, higher distribution rate base, higher return on regulatory assets, and higher transmission peak load. These were partially offset by a lower allowed distribution ROE, the absence of a return on the pension asset within distribution earnings, and lower carrying cost recovery related to the CMC regulatory asset.

The changes in Operating revenues consisted of the following:

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	Increase (Decrease)		Increase
Distribution	$	46	$	189
Transmission	19		76
Energy efficiency	13		43
Other	16		14
	94		322
Regulatory required programs	(133)		245
Total (decrease) increase	$	(39)	$	567

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

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ComEd

Distribution Revenue. Distribution revenues were under a performance-based formula rate through 2023. Starting in 2024, distribution revenues are under a MRP. Both the performance-based formula rate and the MRP require annual reconciliations of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred with certain limitations for the MRP reconciliations. 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, 2024 as compared to the same period in 2023, primarily due to differences in the timing of distribution earnings and higher rate base, partially offset by lower allowed ROE and the absence of a return on the pension asset.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenues increased for the three and nine months ended September 30, 2024 as compared to the same period in 2023, primarily due to higher fully recoverable costs, higher peak load, and the impacts of higher rate base.

Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenues increased for the three and nine months ended September 30, 2024 as compared to the same periods in 2023, primarily due to increased regulatory asset amortization, which is fully recoverable.

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

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. ETAC is a retail customer surcharge collected and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs.

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

The $61 million decrease and $436 million increase in Purchased power expense for the three and nine months ended September 30, 2024 compared to the same periods in 2023, respectively, is offset in Operating revenues as part of regulatory required programs.

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ComEd

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

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting and materials(a)	$	9	$	81
BSC costs	10		43
Pension and non-pension postretirement benefits expense	6		18
Storm-related costs	(7)		(4)
Other(b)	(5)		77
	13		215
Regulatory required programs(c)	12		(15)
Total increase	$	25	$	200

__________

(a)Primarily reflects an updated rate of capitalization of certain overhead costs.

(b)Primarily reflects the reclassification and increase of the FERC audit liability during the current year and an increase in credit loss expense. See Note 2 — Regulatory Matters for additional information regarding the FERC audit liability.

(c)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.

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

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	Increase		Increase
Depreciation and amortization(a)	$	20	$	53
Regulatory asset amortization(b)	10		26
Total increase	$	30	$	79

__________

(a)Reflects ongoing capital expenditures.

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

Effective income tax rates were 9.1% and 22.0% for the three months ended September 30, 2024 and 2023, respectively, and 9.4% and 22.2% for the nine months ended September 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PECO

Results of Operations — PECO

	Three Months Ended September 30,				(Unfavorable) Favorable Variance		Nine Months Ended September 30,				(Unfavorable) Favorable Variance
	2024		2023				2024		2023
Operating revenues	$	1,030	$	1,037	$	(7)	$	2,975	$	2,977	$	(2)
Operating expenses
Purchased power and fuel	386		411		25		1,113		1,197		84
Operating and maintenance	313		277		(36)		876		786		(90)
Depreciation and amortization	108		100		(8)		318		297		(21)
Taxes other than income taxes	61		59		(2)		164		156		(8)
Total operating expenses	868		847		(21)		2,471		2,436		(35)
Gain on sales of assets	—		—		—		4		—		4
Operating income	162		190		(28)		508		541		(33)
Other income and (deductions)
Interest expense, net	(58)		(52)		(6)		(170)		(149)		(21)
Other, net	9		11		(2)		27		26		1
Total other income and (deductions)	(49)		(41)		(8)		(143)		(123)		(20)
Income before income taxes	113		149		(36)		365		418		(53)
Income taxes	(4)		3		7		9		8		(1)
Net income	$	117	$	146	$	(29)	$	356	$	410	$	(54)

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net income decreased by $29 million, due to an increase in credit loss expense, interest expense, and depreciation expense.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net income decreased by $54 million, due to an increase in credit loss expense, interest expense, depreciation expense, and storm costs, partially offset by an increase in revenue as a result of less unfavorable weather impact relative to the same period last year.

The changes in Operating revenues consisted of the following:

	Three Months Ended September 30, 2024						Nine Months Ended September 30, 2024
	(Decrease) Increase						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	—	$	—	$	—	$	57	$	13	$	70
Volume	3		1		4		11		—		11
Pricing	14		2		16		12		—		12
Transmission	(11)		—		(11)		4		—		4
Other	4		1		5		(3)		(3)		(6)
	10		4		14		81		10		91
Regulatory required programs	(20)		(1)		(21)		(28)		(65)		(93)
Total decrease	$	(10)	$	3	$	(7)	$	53	$	(55)	$	(2)

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended September 30, 2024 compared to the same period in 2023, Operating revenues related to weather remained consistent in PECO's service territory. During the nine months ended September 30, 2024 compared to the same period in 2023, Operating revenues related to weather increased due to less unfavorable weather conditions in PECO's service territory.

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PECO

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, 2024 compared to the same period in 2023 and normal weather consisted of the following:

	Three Months Ended September 30,			% Change
PECO Service Territory	2024	2023	Normal	2024 vs. 2023		2024 vs. Normal
Heating Degree-Days	1	18	21	(94.4)	%	(95.2)	%
Cooling Degree-Days	1,062	1,064	1,038	(0.2)	%	2.3	%
	Nine Months Ended September 30,			% Change
	2024	2023	Normal	2024 vs. 2023		2024 vs. Normal
Heating Degree-Days	2,441	2,236	2,853	9.2	%	(14.4)	%
Cooling Degree-Days	1,599	1,297	1,430	23.3	%	11.8	%

Volume. Electric volume, exclusive of the effects of weather, for the three months ended September 30, 2024 compared to the same period in 2023, remained relatively consistent. Electric volume, exclusive of the effects of weather, for the nine months ended September 30, 2024 compared to the same period in 2023, increased due to customer load growth. Natural gas volume for the three and nine months ended September 30, 2024 compared to the same period in 2023, 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)
	2024	2023					2024	2023
Residential	4,146	4,134	0.3	%	0.2	%	10,897	10,186	7.0	%	0.7	%
Small commercial & industrial	2,129	2,070	2.9	%	2.8	%	5,876	5,616	4.6	%	1.5	%
Large commercial & industrial	3,768	3,830	(1.6)	%	(1.5)	%	10,531	10,398	1.3	%	—	%
Public authorities & electric railroads	156	152	2.6	%	2.0	%	470	464	1.3	%	1.3	%
Total electric retail deliveries(a)	10,199	10,186	0.1	%	0.1	%	27,774	26,664	4.2	%	0.6	%

	At September 30,
Number of Electric Customers	2024	2023
Residential	1,529,205	1,531,168
Small commercial & industrial	155,126	155,932
Large commercial & industrial	3,156	3,111
Public authorities & electric railroads	10,716	10,416
Total	1,698,203	1,700,627

__________

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

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

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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)
	2024	2023					2024	2023
Residential	2,359	2,134	10.5	%	13.4	%	25,779	23,697	8.8	%	1.5	%
Small commercial & industrial	1,933	1,939	(0.3)	%	1.4	%	14,742	14,381	2.5	%	(3.3)	%
Large commercial & industrial	1	4	(75.0)	%	(4.6)	%	17	39	(56.4)	%	(9.4)	%
Transportation	5,232	5,278	(0.9)	%	(2.5)	%	17,248	17,482	(1.3)	%	(3.0)	%
Total natural gas retail deliveries(a)	9,525	9,355	1.8	%	1.9	%	57,786	55,599	3.9	%	(1.1)	%

	At September 30,
Number of Natural Gas Customers	2024	2023
Residential	506,476	505,370
Small commercial & industrial	44,682	44,743
Large commercial & industrial	7	9
Transportation	643	629
Total	551,808	550,751

__________

(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, 2024 compared to the same period in 2023 increased primarily due to higher electric DSIC rates in PECO's service territories.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered.

Other revenue primarily includes revenue related to late payment charges. Other revenue for the three and nine months ended September 30, 2024 compared to the same period in 2023 remained relatively consistent.

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

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

The decrease of $25 million and decrease of $84 million for the three and nine months ended September 30, 2024 compared to the same period in 2023, in Purchased power and fuel expense is offset in Operating revenues as part of regulatory required programs.

119

PECO

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

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	Increase (Decrease)		Increase (Decrease)
Credit loss expense	$	19	$	47
BSC costs	6		19
Storm-related costs	(10)		13
Pension and non-pension postretirement benefit expense	2		5
Labor, other benefits, contracting and materials	5		—
Other	8		11
	30		95
Regulatory required programs	6		(5)
Total increase	$	36	$	90

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

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	Increase		Increase
Depreciation and amortization(a)	$	8	$	21
Regulatory asset amortization	—		—
Total increase	$	8	$	21

__________

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

Interest expense, net increased $6 million and $21 million for the three and nine months ended September 30, 2024, compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in the third quarter of 2024.

Effective income tax rates were (3.5)% and 2.0% for the three months ended September 30, 2024 and 2023, respectively, and 2.5% and 1.9% for the nine months ended September 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

120

BGE

Results of Operations — BGE

	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2024		2023				2024		2023
Operating revenues	$	1,044	$	932	$	112	$	3,268	$	2,986	$	282
Operating expenses
Purchased power and fuel	420		380		(40)		1,228		1,145		(83)
Operating and maintenance	281		214		(67)		795		632		(163)
Depreciation and amortization	162		161		(1)		474		487		13
Taxes other than income taxes	86		80		(6)		254		239		(15)
Total operating expenses	949		835		(114)		2,751		2,503		(248)
Operating income	95		97		(2)		517		483		34
Other income and (deductions)
Interest expense, net	(57)		(47)		(10)		(159)		(135)		(24)
Other, net	11		6		5		27		14		13
Total other income and (deductions)	(46)		(41)		(5)		(132)		(121)		(11)
Income before income taxes	49		56		(7)		385		362		23
Income taxes	4		11		7		32		76		44
Net income	$	45	$	45	$	—	$	353	$	286	$	67

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net Income remained consistent with favorable distribution rates, offset by an increase in credit loss expense, various operating expenses and interest expense.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net Income increased $67 million primarily due to favorable distribution rates, partially offset by an increase in storm costs, credit loss expense, various operating expenses and interest expense.

The changes in Operating revenues consisted of the following:

	Three Months Ended September 30, 2024						Nine Months Ended September 30, 2024
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Distribution	$	25	$	23	$	48	$	68	$	82	$	150
Transmission	17		—		17		20		—		20
Other	2		1		3		3		(1)		2
	44		24		68		91		81		172
Regulatory required programs	45		(1)		44		176		(66)		110
Total increase	$	89	$	23	$	112	$	267	$	15	$	282

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.

121

BGE

	At September 30,
Number of Electric Customers	2024	2023
Residential	1,215,873	1,208,230
Small commercial & industrial	115,032	115,557
Large commercial & industrial	13,206	13,007
Public authorities & electric railroads	260	264
Total	1,344,371	1,337,058

	At September 30,
Number of Natural Gas Customers	2024	2023
Residential	658,485	655,753
Small commercial & industrial	37,752	37,950
Large commercial & industrial	6,353	6,289
Total	702,590	699,992

Distribution Revenue increased for the three and nine months ended September 30, 2024, compared to the same period in 2023, 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, 2024, compared to the same period in 2023, primarily due to increases in underlying costs and capital investments.

Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue remained relatively consistent for the three and nine months ended September 30, 2024 compared to the same period in 2023.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.

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

The increase of $40 million and $83 million for the three and nine months ended September 30, 2024 compared to the same period in 2023, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

122

BGE

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

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	(Decrease) Increase		Increase
Storm-related costs	(4)		6
BSC costs	3		16
Credit loss expense	11		19
Labor, other benefits, contracting, and materials	14		14
Other(a)	21		22
	45		77
Regulatory required programs(b)	22		86
Total increase	$	67	$	163

__________

(a)Primarily related to capital write-offs.

(b)Increase due to the cost recovery associated with EmPOWER Maryland. Please refer to 2023 10-K Note 3 — Regulatory Matters for additional information.

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

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	(Decrease) Increase		(Decrease) Increase
Depreciation and amortization	$	(7)	$	(3)
Regulatory required programs(a)	(9)		(49)
Regulatory asset amortization	17		39
Total increase (decrease)	$	1	$	(13)

__________

(a)Decrease due to the cost recovery associated with EmPOWER Maryland. Please refer to 2023 10-K Note 3 — Regulatory Matters for additional information.

Interest expense, net increased by $10 million and $24 million for the three and nine months ended September 30, 2024 , respectively compared to the same period in 2023, primarily due to an increase in interest rates and the issuance of debt in the second quarter of 2024 and 2023.

Taxes other than income taxes increased by $6 million and $15 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023, primarily due to increased property taxes.

Other, net increased by $5 million and $13 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023, primarily due to increased interest income and higher AFUDC equity.

Effective income tax rates were 8.2% and 19.6% for the three months ended September 30, 2024 and 2023, respectively, and 8.3% and 21.0% for the nine months ended September 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

123

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, 2024 compared to the same period in 2023. See the Results of Operations for Pepco, DPL, and ACE for additional information.

	Three Months Ended September 30,				Favorable Variance		Nine Months Ended September 30,				Favorable Variance
	2024		2023				2024		2023
PHI	$	278	$	232	$	46	$	603	$	490	$	113
Pepco	140		120		20		323		249		74
DPL	55		43		12		156		128		28
ACE	83		71		12		133		122		11
Other(a)	—		(2)		2		(9)		(9)		—

__________

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

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net Income increased by $46 million primarily due to higher ACE and DPL Delaware electric distribution rates, favorable impacts of the Pepco Maryland multi-year plans, higher transmission rates at Pepco, and a decrease in storm costs and various operating expenses, partially offset by an increase in interest expense.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net Income increased by $113 million primarily due to the favorable impacts of the Pepco Maryland multi-year plans including the recognition of the reconciliations, the absence of an increase in environmental liabilities at Pepco, higher ACE and DPL Delaware electric distribution rates, higher transmission rates at Pepco and DPL, and a decrease in storm costs and various operating expenses, partially offset by increases in interest expense and depreciation expense.

124

Pepco

Results of Operations — Pepco

	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2024		2023				2024		2023
Operating revenues	$	861	$	822	$	39	$	2,320	$	2,174	$	146
Operating expenses
Purchased power	294		288		(6)		808		750		(58)
Operating and maintenance	140		149		9		392		440		48
Depreciation and amortization	102		112		10		307		329		22
Taxes other than income taxes	114		109		(5)		317		291		(26)
Total operating expenses	650		658		8		1,824		1,810		(14)
Operating income	211		164		47		496		364		132
Other income and (deductions)
Interest expense, net	(50)		(41)		(9)		(142)		(122)		(20)
Other, net	11		18		(7)		43		50		(7)
Total other income and (deductions)	(39)		(23)		(16)		(99)		(72)		(27)
Income before income taxes	172		141		31		397		292		105
Income taxes	32		21		(11)		74		43		(31)
Net income	$	140	$	120	$	20	$	323	$	249	$	74

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net Income increased by $20 million primarily due to higher transmission rates, favorable impacts of the Maryland multi-year plans, customer growth, and decrease in storm costs, partially offset by increases in depreciation expense and interest expense.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net Income increased by $74 million primarily due to the favorable impacts of the Maryland multi-year plans including the recognition of the reconciliations, the absence of an increase in environmental liabilities, higher transmission rates, customer growth, and decrease in storm costs partially offset by increases in depreciation expense and interest expense.

The changes in Operating revenues consisted of the following:

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	Increase		Increase (Decrease)
Distribution	$	14	$	30
Transmission	24		48
Other	1		(1)
	39		77
Regulatory required programs	—		69
Total increase	$	39	$	146

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

125

Pepco

	At September 30,
Number of Electric Customers	2024	2023
Residential	875,456	862,321
Small commercial & industrial	54,058	54,082
Large commercial & industrial	23,054	22,952
Public authorities & electric railroads	207	205
Total	952,775	939,560

Distribution Revenue increased for the three and nine months ended September 30, 2024 compared to the same period in 2023 primarily due to favorable impacts of the Maryland multi-year plans and customer growth.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and nine months ended September 30, 2024, compared to the same period in 2023, primarily due to increases in underlying costs and capital investments.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore, Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.

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

The increase of $6 million and $58 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

126

Pepco

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

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	(Decrease) Increase		Increase (Decrease)
BSC and PHISCO costs	$	(3)	$	11
Credit loss expense	(3)		(3)
Storm-related costs	(4)		(4)
Pension and non-pension postretirement benefits expense	—		(2)
Labor, other benefits, contracting and materials(a)	(7)		(36)
Pepco Maryland multi-year plan reconciliations(b)	(3)		(27)
Other (c)	—		(21)
	(20)		(82)
Regulatory required programs(d)	11		34
Total decrease	$	(9)	$	(48)

_________

(a)Primarily reflects the absence of an increase in environmental liabilities for the nine months ended September 30, 2024 compared to the same period in 2023.

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

(c)Primarily relates to a revenue deferral mechanism approved by the MDPSC to capture rate increases attributable to April 1, 2024 through June 30, 2024.

(d)Increase primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 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, 2024		Nine Months Ended September 30, 2024
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	7	$	18
Regulatory asset amortization	—		—
Regulatory required programs	(17)		(40)
Total decrease	$	(10)	$	(22)

__________

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

Taxes other than income taxes increased $5 million and $26 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023, primarily due to increases in utility taxes, which are offset in revenues, and property taxes.

Interest expense, net increased by $9 million and $20 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023, primarily due to increases in interest rates and the issuance of debt in 2023 and 2024.

Effective income tax rates were 18.6% and 14.9% for the three months ended September 30, 2024 and 2023, respectively, and 18.6% and 14.7% for the nine months ended September 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

127

DPL

Results of Operations — DPL

	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2024		2023				2024		2023
Operating revenues	$	462	$	450	$	12	$	1,343	$	1,273	$	70
Operating expenses
Purchased power and fuel	203		201		(2)		573		562		(11)
Operating and maintenance	92		104		12		284		278		(6)
Depreciation and amortization	62		62		—		183		182		(1)
Taxes other than income taxes	20		19		(1)		59		57		(2)
Total operating expenses	377		386		9		1,099		1,079		(20)
Operating income	85		64		21		244		194		50
Other income and (deductions)
Interest expense, net	(22)		(18)		(4)		(69)		(53)		(16)
Other, net	6		5		1		20		12		8
Total other income and (deductions)	(16)		(13)		(3)		(49)		(41)		(8)
Income before income taxes	69		51		18		195		153		42
Income taxes	14		8		(6)		39		25		(14)
Net income	$	55	$	43	$	12	$	156	$	128	$	28

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net income increased $12 million primarily due to higher Delaware electric distribution rates, and a decrease in storm costs, partially offset by unfavorable weather conditions at Delaware electric service territories.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2024. Net income increased $28 million primarily due to higher Delaware electric distribution rates, favorable weather conditions at Delaware electric and natural gas service territories, and higher transmission rates, partially offset by an increase in interest expense.

The changes in Operating revenues consisted of the following:

	Three Months Ended September 30, 2024						Nine Months Ended September 30, 2024
	(Decrease) Increase						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	(4)	$	—	$	(4)	$	5	$	4	$	9
Volume	4		—		4		3		—		3
Distribution	12		1		13		34		3		37
Transmission	(2)		—		(2)		11		—		11
Other	1		—		1		3		—		3
	11		1		12		56		7		63
Regulatory required programs	2		(2)		—		41		(34)		7
Total increase (decrease)	$	13	$	(1)	$	12	$	97	$	(27)	$	70

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

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

128

DPL

weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended September 30, 2024 compared to the same period in 2023, Operating revenues related to weather decreased due to unfavorable weather conditions in Delaware electric service territories. During the nine months ended September 30, 2024 compared to the same period in 2023, Operating revenues related to weather increased due to favorable weather conditions in Delaware electric and natural gas service territories.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in the Delaware electric service territory and a 30-year period in the Delaware natural gas service territory. The changes in heating and cooling degree days in the Delaware service territory for the three and nine months ended September 30, 2024, compared to same period in 2023 and normal weather consisted of the following:

	Three Months Ended September 30,			% Change
Delaware Electric Service Territory	2024	2023	Normal	2024 vs. 2023		2024 vs. Normal
Heating Degree-Days	13	37	28	(64.9)	%	(53.6)	%
Cooling Degree-Days	856	996	920	(14.1)	%	(7.0)	%
	Nine Months Ended September 30,			% Change
Delaware Electric Service Territory	2024	2023	Normal	2024 vs. 2023		2024 vs. Normal
Heating Degree-Days	2,620	2,306	2,924	13.6	%	(10.4)	%
Cooling Degree-Days	1,256	1,249	1,261	0.6	%	(0.4)	%

	Three Months Ended September 30,			% Change
Delaware Natural Gas Service Territory	2024	2023	Normal	2024 vs. 2023		2024 vs. Normal
Heating Degree-Days	13	37	35	(64.9)	%	(62.9)	%
	Nine Months Ended September 30,			% Change
Delaware Natural Gas Service Territory	2024	2023	Normal	2024 vs. 2023		2024 vs. Normal
Heating Degree-Days	2,620	2,306	2,993	13.6	%	(12.5)	%

Volume, exclusive of the effects of weather, increased for both the three and nine months ended September 30, 2024 compared to the same period in 2023, primarily due to an increase in customer usage and customer growth.

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)
	2024	2023					2024	2023
Residential	974	995	(2.1)	%	6.3	%	2,529	2,403	5.2	%	1.9	%
Small commercial & industrial	402	405	(0.7)	%	3.2	%	1,094	1,081	1.2	%	(0.3)	%
Large commercial & industrial	811	849	(4.5)	%	(2.7)	%	2,285	2,349	(2.7)	%	(3.1)	%
Public authorities & electric railroads	8	7	14.3	%	12.4	%	22	23	(4.3)	%	(5.1)	%
Total electric retail deliveries(a)	2,195	2,256	(2.7)	%	2.3	%	5,930	5,856	1.3	%	(0.5)	%

129

DPL

	At September 30,
Number of Total Electric Customers (Maryland and Delaware)	2024	2023
Residential	489,634	484,425
Small commercial & industrial	64,626	64,101
Large commercial & industrial	1,267	1,245
Public authorities & electric railroads	598	593
Total	556,125	550,364

__________

(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)
	2024	2023					2024	2023
Residential	397	414	(4.1)	%	4.1	%	5,162	4,781	8.0	%	(1.8)	%
Small commercial & industrial	343	350	(2.0)	%	2.9	%	2,590	2,494	3.8	%	(5.4)	%
Large commercial & industrial	408	381	7.1	%	7.1	%	1,239	1,166	6.3	%	6.3	%
Transportation	1,190	1,119	6.3	%	7.2	%	4,491	4,350	3.2	%	0.4	%
Total natural gas deliveries(a)	2,338	2,264	3.3	%	6.0	%	13,482	12,791	5.4	%	(1.2)	%

	At September 30,
Number of Delaware Natural Gas Customers	2024	2023
Residential	130,885	129,436
Small commercial & industrial	10,110	10,039
Large commercial & industrial	14	14
Transportation	161	165
Total	141,170	139,654

__________

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

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

Distribution Revenue increased for the three and nine months ended September 30, 2024 compared to the same period in 2023 primarily due to favorable impacts of the higher electric distribution rates in Delaware that became effective July 2023, and higher natural gas DSIC rates in Delaware that became effective in January 2024, partially offset by lower electric DSIC rates in Delaware that became effective in January 2024.

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 months ended September 30, 2024 compared to the same period in 2023, transmission revenue remained relatively consistent. During the nine months ended September 30, 2024 compared to the same period in 2023, transmission revenue increased due to increases in underlying costs and capital investments.

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

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes

130

DPL

other than income taxes. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.

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

The increase of $2 million and $11 million for the three and nine months ended September 30, 2024, compared to the same period in 2023, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	(Decrease) Increase		Increase (Decrease)
BSC and PHISCO costs	$	—	$	6
Labor and contracting	(3)		—
Pension and non-pension postretirement benefits expense	(1)		(1)
Credit loss expense	(1)		(2)
Storm-related Costs	(8)		(3)
Other	(2)		(1)
	(15)		(1)
Regulatory required programs (a)	3		7
Total (decrease) increase	$	(12)	$	6

__________

(a)Increase primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 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, 2024		Nine Months Ended September 30, 2024
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	3	$	6
Regulatory asset amortization	—		1
Regulatory required programs	(3)		(6)
Total increase	$	—	$	1

__________

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

Interest expense, net increased by $4 million and $16 million for the three and nine months ended September 30, 2024 compared to the same period in 2023, respectively, primarily due to an increase in interest rates and the issuance of debt in 2023 and 2024.

Other, net increased by $1 million and $8 million for the three and nine months ended September 30, 2024 compared to the same period in 2023, respectively, primarily due to higher AFUDC equity.

131

DPL

Effective income tax rates were 20.3% and 15.7% for the three months ended September 30, 2024 and 2023, respectively, and 20.0% and 16.3% for the nine months ended September 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

132

ACE

Results of Operations — ACE

	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2024		2023				2024		2023
Operating revenues	$	540	$	502	$	38	$	1,280	$	1,172	$	108
Operating expenses
Purchased power	245		221		(24)		557		493		(64)
Operating and maintenance	96		94		(2)		274		259		(15)
Depreciation and amortization	67		77		10		214		212		(2)
Taxes other than income taxes	2		2		—		7		7		—
Total operating expenses	410		394		(16)		1,052		971		(81)
Operating income	130		108		22		228		201		27
Other income and (deductions)
Interest expense, net	(21)		(19)		(2)		(59)		(52)		(7)
Other, net	4		5		(1)		12		13		(1)
Total other income and (deductions)	(17)		(14)		(3)		(47)		(39)		(8)
Income before income taxes	113		94		19		181		162		19
Income taxes	30		23		(7)		48		40		(8)
Net income	$	83	$	71	$	12	$	133	$	122	$	11

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. Net income increased by $12 million primarily due to higher distribution rates.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. Net income increased by $11 million primarily due to higher distribution rates partially offset by increases in depreciation expense and interest expense.

The changes in Operating revenues consisted of the following:

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	Increase		Increase
Distribution	$	16	$	45
Transmission	4		4
	20		49
Regulatory required programs	18		59
Total increase	$	38	$	108

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not impacted by abnormal weather or usage per customer as a result of the CIP which became effective, prospectively, in the third quarter of 2021. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

133

ACE

	At September 30,
Number of Electric Customers	2024	2023
Residential	507,060	504,330
Small commercial & industrial	62,761	62,410
Large commercial & industrial	2,848	2,980
Public authorities & electric railroads	707	729
Total	573,376	570,449

Distribution Revenue increased for the three and nine months ended September 30, 2024 compared to the same period in 2023 due to higher distribution rates that became effective December 2023 and the expiration of customer credits related to the TCJA tax benefits.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and nine months ended September 30, 2024 compared to the same period in 2023 due to increases in underlying costs and capital investments.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bond Charge, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

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

The increase of $24 million and $64 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023 in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

134

ACE

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

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	(Decrease) Increase		Increase (Decrease)
BSC and PHISCO costs	$	—	$	7
Labor and contracting	(4)		(6)
Storm-related costs	(3)		1
Other	—		2
	(7)		4
Regulatory required programs(a)	9		11
Total increase	$	2	$	15

__________

(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge.

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

	Three Months Ended September 30, 2024		Nine Months Ended September 30, 2024
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	5	$	13
Regulatory asset amortization	1		4
Regulatory required programs	(16)		(15)
Total (decrease) increase	$	(10)	$	2

__________

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

Interest expense, net increased $2 million and $7 million for the three and nine months ended September 30, 2024, respectively, compared to the same period in 2023 primarily due to increases in interest rates and the issuance of debt in 2023 and 2024.

Effective income tax rates were 26.5% and 24.5% for the three months ended September 30, 2024 and 2023, respectively, and 26.5% and 24.7% for the nine months ended September 30, 2024 and 2023, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

135

Liquidity and Capital Resources (All Registrants)

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

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $4.0 billion. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

Cash Flows from Operating Activities

The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period that began in June 2022, and all of its costs of doing so will be recovered through a rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset.

See Note 3 — Regulatory Matters of the 2023 Form 10-K and Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.

136

The following table provides a summary of the change in cash flows from operating activities for the nine months ended September 30, 2024 and 2023 by Registrant:

Increase (decrease) in cash flows from operating activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income (loss)	$	102	$	1	$	(54)	$	67	$	113	$	74	$	28	$	11
Adjustments to reconcile net income to cash:
Non-cash operating activities	605		447		90		(10)		3		(71)		27		62
Collateral received (paid), net	204		(7)		—		22		192		25		122		45
Income taxes	(68)		(159)		(131)		(70)		(92)		(60)		(40)		(8)
Pension and non-pension postretirement benefit contributions	(43)		15		(2)		(19)		(64)		2		(1)		(6)
Regulatory assets and liabilities, net	589		670		16		82		(156)		(47)		(74)		(34)
Changes in working capital and other assets and liabilities	(538)		84		(199)		(68)		72		37		(9)		39
Increase (decrease) in cash flows from operating activities	$	851	$	1,051	$	(280)	$	4	$	68	$	(40)	$	53	$	109

Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. Significant operating cash flow impacts for the Registrants for the nine months ended September 30, 2024 and 2023 were as follows:

•See Note 14 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.

•Changes in collateral depended upon whether the Registrant was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The change in Collateral received (paid), net, when comparing the nine months ended September 30, 2024 to the nine months ended September 30, 2023, is due to stable energy prices for the current year. See Note 8 — Derivative Financial Instruments for additional information.

•See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.

•Changes in Pension and non-pension postretirement benefit contributions relates to Exelon's increased contributions to the Qualified Plans during the nine months ended September 30, 2024. See Note 14 — Retirement Benefits of the 2023 Form 10-K for additional information.

•Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differing from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $266 million and $299 million for the nine months ended September 30, 2024 and 2023, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $94 million, $34 million, $14 million, and $24 million for the nine months ended September 30, 2024 and $102 million, $49 million, $19 million, and $14 million for the nine months ended September 30, 2023, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the nine months ended September 30, 2024 and 2023. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

137

•Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $(116) million and $(538) 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, 2024, the established pricing resulted in ComEd owing payments to nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts payable and accrued expense.

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the nine months ended September 30, 2024 and 2023 by Registrant:

Increase (decrease) in cash flows from investing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	379	$	307	$	(57)	$	(47)	$	167	$	38	$	12	$	111
Proceeds from sales of assets and businesses	38		—		—		—		—		—		—		—
Changes in intercompany money pool	—		—		(38)		—		—		7		10		—
Other investing activities	(16)		—		4		4		(8)		(8)		—		—
Increase (decrease) in cash flows from investing activities	$	401	$	307	$	(91)	$	(43)	$	159	$	37	$	22	$	111

Significant investing cash flow impacts for the Registrants for nine months ended September 30, 2024 and 2023 were as follows:

•Changes in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants.

•Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the nine months ended September 30, 2024 and 2023 by Registrant:

(Decrease) increase in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	(626)	$	(629)	$	74	$	13	$	65	$	216	$	52	$	(203)
Long-term debt, net	(452)		(425)		50		400		(33)		(75)		17		25
Changes in intercompany money pool	—		—		—		—		(8)		—		—		(17)
Issuance of common stock	148		—		—		—		—		—		—		—
Dividends paid on common stock	(68)		(22)		3		(39)		—		(86)		(65)		11
Distributions to member	—		—		—		—		(139)		—		—		—
Contributions from parent/member	—		(453)		247		—		30		(48)		61		20
Other financing activities	21		—		(1)		(2)		3		7		—		(2)
(Decrease) increase in cash flows from financing activities	$	(977)	$	(1,529)	$	373	$	372	$	(82)	$	14	$	65	$	(166)

138

Significant financing cash flow impacts for the Registrants for the nine months ended September 30, 2024 and 2023 were as follows:

•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants.

•Long-term debt, net, varies due to debt issuances and redemptions each year. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the debt redemptions table below for additional information.

•Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.

•Issuance of common stock relates to the August 2024 issuance of Exelon common stock. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

•Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 18 — Commitments and Contingencies of the 2023 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.

Debt

See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

During the nine months ended September 30, 2024, the following long-term debt was retired and/or redeemed:

Company	Type	Interest Rate		Maturity	Amount
Exelon	SMBC Term Loan Agreement	SOFR plus 0.85%		April 8, 2024	$	500
Exelon	Software Licensing Agreement	3.62	%	December 1, 2025	$	1
Exelon	Software Licensing Agreement	3.95	%	May 1, 2024	$	2
ComEd	First Mortgage Bonds	3.10	%	November 1, 2024	$	250
Pepco	First Mortgage Bonds	3.60	%	March 15, 2024	$	400
DPL(a)	Unsecured tax-exempt bonds	4.32	%	July 1, 2024	$	33
ACE	First Mortgage Bonds	3.38	%	September 1, 2024	150

__________

(a)Variable interest on the DPL unsecured tax-exempt bonds reset on a weekly basis.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 2024 and for the fourth quarter of 2024 were as follows:

Period	Declaration Date	Shareholder of Record Date	Dividend Payable Date	Cash per Share(a)
First Quarter 2024	February 21, 2024	March 4, 2024	March 15, 2024	$	0.3800
Second Quarter 2024	April 30, 2024	May 13, 2024	June 14, 2024	$	0.3800
Third Quarter 2024	July 30, 2024	August 12, 2024	September 13, 2024	$	0.3800
Fourth Quarter 2024	October 29, 2024	November 11, 2024	December 13, 2024	$	0.3800

__________

(a)Exelon's Board of Directors approved an updated dividend policy for 2024. The 2024 quarterly dividend will be $0.38 per share.

139

Credit Matters and Cash Requirements

The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $3.4 billion was available to support additional commercial paper as of September 30, 2024, 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, 2024 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the 2023 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flows from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements.

On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of common stock under the Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the Equity Distribution Agreement. In November and December 2023, Exelon issued approximately 3.6 million shares of common stock at an average gross price of $39.58 per share. In the third quarter 2024, Exelon issued approximately 4.0 million shares of Common Stock at an average gross price of $37.60 per share. The net proceeds from the fourth quarter 2023 issuances and third quarter 2024 issuances were $140 million and $147 million, respectively, which were used for general corporate purposes. As of September 30, 2024, $708 million of Common stock remained available for sale pursuant to the ATM program.

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, 2024 and available credit facility capacity prior to any incremental collateral at September 30, 2024:

	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	19	$	—	$	913
PECO	—		18		596
BGE	—		37		575
Pepco	—		—		249
DPL	—		9		300
ACE	—		—		131

__________

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

Capital Expenditure Spending

As of September 30, 2024, the most recent estimates of capital expenditures for plant additions and improvements for 2024 are as follows:        

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(In millions)	Transmission	Distribution	Gas	Total(a)
Exelon	N/A	N/A	N/A	$	7,450
ComEd	450	1,775	N/A	2,225
PECO	100	1,200	375	1,700
BGE	350	675	500	1,550
PHI	550	1,325	100	1,975
Pepco	225	750	N/A	975
DPL	200	300	100	625
ACE	125	275	N/A	400

__________

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

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

Retirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $93 million in 2024. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery).

To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.

See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2023 Form 10-K for additional information on pension and OPEB contributions.

Credit Facilities

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

See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.

141

Security Ratings

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

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

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for the Registrants did not change for the nine months ended September 30, 2024.

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, 2024, are presented in the following table:

	During the Nine Months Ended September 30, 2024				At September 30, 2024
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	626	$	—	$	177
PECO	241		(255)		89
BSC	—		(420)		(236)
PHI Corporate	—		(86)		(75)
PCI	45		—		45

	During the Nine Months Ended September 30, 2024				At September 30, 2024
PHI Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Pepco	$	171	$	(35)	$	—
DPL	130		(33)		—
ACE	—		(197)		—

Shelf Registration Statements

As of January 1st, 2024 Exelon and the Utility Registrants had an effective combined shelf registration statement, unlimited in amount (“Legacy Registration Statement”). On February 20, 2024, Exelon Corporation filed with the SEC Post-Effective Amendment 1 to its Legacy Registration Statement to remove and withdraw registration of all registered securities of ACE, DPL, PECO and BGE.

On February 21, 2024, Exelon Corporation, together with Pepco and ComEd as co-registrants, filed with the SEC Post-Effective Amendment 2 to its Legacy Registration Statement. Post-Effective Amendment 2 amends the Legacy Registration Statement to include an authorized limit of $7,200 million, which can be used to issue Exelon Corporation debt securities and equity securities, as well as Pepco and ComEd debt securities, through the expiration date of August 3, 2025. The amended Legacy Registration Statement was declared effective by the SEC on April 30, 2024. 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

142

securities through the expiration date of February 20, 2027. The ability of Exelon Corporation, ComEd, Pepco, PECO and BGE to sell securities off their corresponding registration Statements, or to access the private placement markets, will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

As a result of Post-Effect Amendment 1, DPL and ACE filed to deregister all securities that remain unsold. DPL and ACE periodically issue securities through the private placement markets. 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.

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, 2024
	Short-term Financing Authority				Remaining Long-term Financing Authority
	Commission	Expiration Date	Amount		Commission	Expiration Date	Amount
ComEd	FERC	December 31, 2025	$	2,500	ICC	January 1, 2027 & May 1, 2027	$	2,318
PECO(c)	FERC	December 31, 2025	1,500		PAPUC	December 31, 2024	—
BGE	FERC	December 31, 2025	700		MDPSC	N/A	300
Pepco(a)	FERC	December 31, 2025	500		MDPSC / DCPSC	December 31, 2025	375
DPL(a)	FERC	December 31, 2025	500		MDPSC / DEPSC	December 31, 2025	375
ACE(b)	NJBPU	December 31, 2025	350		NJBPU	December 31, 2024	375

__________

(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, 2025.

(b)On June 24, 2024, ACE filed an application with the NJBPU for renewal of their long-term financing authority through December 31, 2026. ACE expects approval of their application by December 31, 2024.

(c)On October 16, 2024, PECO filed an application for $3.5 billion with the PAPUC for a new long-term financing authority order through December 31, 2027. PECO expects approval of their application by December 31, 2024.

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ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

•Commodity price risk, which is discussed further below.

•Counterparty credit risk associated with non-performance by counterparties on executed derivative instruments and participation in all, or some of the established, wholesale spot energy markets that are administered by PJM. The credit policies of PJM may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of counterparty credit risk related to derivative instruments.

•Equity price and interest rate risk associated with Exelon’s pension and OPEB plan trusts. See Note 7 — Retirement Benefits of the 2023 Form 10-K for additional information.

•Interest rate risk associated with changes in interest rates for the Registrants’ outstanding long-term debt. This risk is significantly reduced as substantially all of the Registrants’ outstanding debt has fixed interest rates. There is inherent interest rate risk related to refinancing maturing debt by issuing new long-term debt. The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. In addition, Exelon may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges, or to lock in rate levels on borrowings, which are typically designated as economic hedges. See Note 8 – Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

The Registrants operate primarily under cost-based rate regulation limiting exposure to the effects of market risk. Hedging programs are utilized to reduce exposure to energy and natural gas price volatility and have no direct earnings impacts as the costs are fully recovered through regulatory-approved recovery mechanisms.

Exelon manages these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. Risk management issues are reported to Exelon’s Executive Committee, the Risk Management Committees of each Utility Registrant, and the Audit and Risk Committee of Exelon’s Board of Directors.

Commodity Price Risk

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity and natural gas.

ComEd entered into 20-year floating-to-fixed renewable energy swap contracts beginning in June 2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. PECO, BGE, Pepco, DPL, and ACE have contracts to procure electric supply that are executed through a competitive procurement process. PECO, BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.

PECO, BGE, and DPL also have executed derivative natural gas contracts, which qualify for NPNS, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their financial statements.

For additional information on these contracts, see Note 8 — Derivative Financial Instruments and Note 10 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements.

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The following table presents the maturity and source of fair value for Exelon’s and ComEd’s mark-to-market commodity contract net liabilities. These net liabilities are associated with ComEd’s floating-to-fixed energy swap contracts with unaffiliated suppliers. The table provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Exelon's and ComEd's total mark-to-market net liabilities. Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract net liabilities giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 10 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

	Maturities Within												Total Fair Value
Commodity derivative contracts(a):	2024		2025		2026		2027		2028		2029 and Beyond
Prices based on model or other valuation methods (Level 3)	$	(11)	$	(22)	$	(20)	$	(19)	$	(21)	$	(72)	$	(165)

_________

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

ITEM 4.    CONTROLS AND PROCEDURES

During the third quarter of 2024, each of the Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to that Registrant's management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of September 30, 2024, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. In the first quarter of 2024, ComEd and PECO implemented a new customer care and billing information system replacing the existing system. ComEd and PECO expect the new system to further automate, enhance and standardize the processes by which they engage with their customers. As part of this system implementation, ComEd and PECO appropriately considered the impacts to internal controls over financial reporting. There were no other changes in internal control over financial reporting that occurred during the three and nine months ended September 30, 2024, 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 2023 Form 10-K, (b) Notes 3 — Regulatory Matters and 18 — Commitments and Contingencies of the 2023 Form 10-K, and (c) Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.

ITEM 1A.    RISK FACTORS

Risks Related to All Registrants

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At September 30, 2024, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2023 Form 10-K in ITEM 1A. RISK FACTORS.

ITEM 5.    OTHER INFORMATION

All Registrants

None.

ITEM 6.    EXHIBITS

Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis and the relevant. Registrant agrees to furnish a copy of any such instrument to the Commission upon request.

(4) Instruments Defining the Rights of Securities Holders, Including Indentures

PECO Energy Company
Exhibit No.	Description	Location
4-1	Supplemental Indenture to PECO Energy Company's First and Refunding Mortgage dated as of August 15, 2024	File No. 001-16844, Form 8-K dated September 10, 2024, Exhibit 4.1

(10) Material Contracts

Exelon Corporation
Exhibit No.	Description	Location
10-1	Amended and Restated Credit Agreement for $900,000,000 dated August 29, 2024 between Exelon, JPMorgan Chase Bank (JPMCB), as Administrative Agent, and various financial institutions	Filed herewithin
10-2	Amended and Restated Credit Agreement for $1,000,000,000 dated August 29, 2024 between ComEd, JPMCB, as Administrative Agent, and various financial institutions	Filed herewithin
10-3	Amended and Restated Credit Agreement for $600,000,000 dated August 29, 2024 between PECO, JPMCB, as Administrative Agent, and various financial institutions	Filed herewithin
10-4	Amended and Restated Credit Agreement for $600,000,000 dated August 29, 2024 between BGE, JPMCB, as Administrative Agent, and various financial institutions	Filed herewithin
10-5	Amended and Restated Credit Agreement for $900,000,000 dated August 29, 2024 between the PHI Utilities, JPMCB, as Administrative Agent, and various financial institutions	Filed herewithin

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, 2024 filed by the following officers for the following companies:

146

Exelon Corporation
Exhibit No.	Description
31-1	Filed by Calvin G. Butler, Jr. for Exelon Corporation
31-2	Filed by Jeanne M. Jones for Exelon Corporation
Commonwealth Edison Company
Exhibit No.	Description
31-3	Filed by Gil C. Quiniones for Commonwealth Edison Company
31-4	Filed by Joshua S. Levin for Commonwealth Edison Company
PECO Energy Company
Exhibit No.	Description
31-5	Filed by David M. Velazquez 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 Carim V. Khouzami 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 David M. Vahos 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 David M. Vahos 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 David M. Vahos 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 David M. Vahos 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, 2024 filed by the following officers for the following companies:

147

Exelon Corporation
Exhibit No.	Description
32-1	Filed by Calvin G. Butler, Jr. for Exelon Corporation
32-2	Filed by Jeanne M. Jones for Exelon Corporation
Commonwealth Edison Company
Exhibit No.	Description
32-3	Filed by Gil C. Quiniones for Commonwealth Edison Company
32-4	Filed by Joshua S. Levin for Commonwealth Edison Company
PECO Energy Company
Exhibit No.	Description
32-5	Filed by David M. Velazquez 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 Carim V. Khouzami 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 David M. Vahos 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 David M. Vahos 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 David M. Vahos 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 David M. Vahos 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)

148

SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON CORPORATION

/s/    CALVIN G. BUTLER, JR.	/s/    JEANNE M. JONES
Calvin G. Butler, Jr.	Jeanne M. Jones
President, Chief Executive Officer (Principal Executive Officer) and Director	Executive Vice President and Chief Financial Officer (Principal Financial Officer)
/s/ ROBERT A. KLECZYNSKI
Robert A. Kleczynski
Senior Vice President, Corporate Controller and Tax (Principal Accounting Officer)

October 30, 2024

149

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/    CAROLINE FULGINITI
Caroline Fulginiti
Vice President and Assistant Controller, Exelon (Principal Accounting Officer, ComEd)

October 30, 2024

150

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PECO ENERGY COMPANY

/s/   DAVID M. VELAZQUEZ	/s/    MARISSA E. HUMPHREY
David M. Velazquez	Marissa E. Humphrey
President, Chief Executive Officer (Principal Executive Officer) and Director	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/    MARIANA HUFFORD
Mariana Hufford
Director, Accounting (Principal Accounting Officer)

October 30, 2024

151

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BALTIMORE GAS AND ELECTRIC COMPANY

/s/    CARIM V. KHOUZAMI	/s/ MICHAEL J. CLOYD
Carim V. Khouzami	Michael J. Cloyd
President, Chief Executive Officer (Principal Executive Officer) and Director	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/ DAMON M. SCOLERI
Damon M. Scoleri
Director, Accounting (Principal Accounting Officer)

October 30, 2024

152

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/    DAVID M. VAHOS
J. Tyler Anthony	David M. Vahos
President, Chief Executive Officer (Principal Executive Officer) and Director	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/ JASON T. JONES
Jason T. Jones
Director, Accounting (Principal Accounting Officer)

October 30, 2024

153

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/    DAVID M. VAHOS
J. Tyler Anthony	David M. Vahos
President, Chief Executive Officer (Principal Executive Officer) and Director	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/ JASON T. JONES
Jason T. Jones
Director, Accounting (Principal Accounting Officer)

October 30, 2024

154

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/    DAVID M. VAHOS
J. Tyler Anthony	David M. Vahos
President, Chief Executive Officer (Principal Executive Officer) and Director	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/ JASON T. JONES
Jason T. Jones
Director, Accounting (Principal Accounting Officer)

October 30, 2024

155

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/    DAVID M. VAHOS
J. Tyler Anthony	David M. Vahos
President, Chief Executive Officer (Principal Executive Officer) and Director	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
/s/ JASON T. JONES
Jason T. Jones
Director, Accounting (Principal Accounting Officer)

October 30, 2024

156