Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Exelon

Executive Overview

Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through its six reportable segments: ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.

Exelon’s consolidated financial information includes the results of its seven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders by Registrant for the three and nine months ended September 30, 2025 compared to the same period in 2024. For additional information regarding the financial results for the three and nine months ended September 30, 2025 and 2024, see the discussions of Results of Operations by Registrant.


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

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

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

Favorable impacts of rates at ComEd, PECO, BGE, and PHI;
Lower storm costs at PECO, due to deferral of extraordinary February and June storm costs;
Timing of income tax expenses at PECO;
Higher return on regulatory assets at ComEd;
Higher AFUDC at ComEd; and
Lower storm costs and credit loss expense at BGE.

The increases were partially offset by:

Timing of distribution earnings at ComEd;
Higher depreciation expense at PECO; and
Higher interest expense at PHI and Exelon Corporate.

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

Favorable impacts of rates at ComEd, PECO, BGE and PHI;
Timing of income tax expenses at PECO;
Less unfavorable weather at PECO;
Lower storm costs at PECO and BGE;
Higher return on regulatory assets at ComEd;
Timing of distribution earnings at ComEd; and
Higher AFUDC at ComEd.

The increases were partially offset by:

Higher interest expense at PECO, BGE, PHI, and Exelon Corporate;
Customer Relief Fund contribution at Exelon Corporate;
Higher depreciation expense at PECO and PHI;
Lower transmission peak load due to lower energy demand at ComEd;
Lower impacts of the Maryland multi-year plan reconciliations at PHI; and
Lower AFUDC at PHI.

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

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



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


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






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

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


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


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


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

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

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2025 and 2024 ranged from 24.0% to 29.0%.

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

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

(c)Represents the probable disallowance of certain capitalized costs.

Significant 2025 Transactions and Developments

Distribution Base Rate Case Proceedings

The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2025. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Completed Distribution Base Rate Case Proceedings


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

Pending Distribution Base Rate Case Proceedings


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Requested ROE	Expected Approval Timing
Pepco - Maryland	October 14, 2025	Electric	$	133	10.50%	Third quarter of 2026
DPL - Delaware	September 20, 2024 (amended September 5, 2025)	Natural Gas	$	37	10.65%	First quarter of 2026
ACE - New Jersey	November 21, 2024	Electric	$	109	10.70%	Fourth quarter of 2025

Transmission Formula Rates

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


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

ComEd's FERC Audit

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

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

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

Other Key Business Drivers and Management Strategies

The following discussion of other key business drivers and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business in the 2024 Form 10-K, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the 2024 Form 10-K, and Note 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.

Allocation of Income Taxes to Regulated Utilities (All Registrants)

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

For the Utility Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a material reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that are being amortized and flowed through to customers as well as a reduction in the accumulated deferred income taxes included in rate base for ratemaking purposes of approximately $1.2 billion - $1.7 billion.

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

Legislative and Regulatory Developments

Infrastructure Investment and Jobs Act

On November 15, 2021, the $1.2 trillion IIJA was signed into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. The Registrants continue to evaluate programs under the legislation and consider possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.

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

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

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

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

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

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

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

One Big Beautiful Bill Act (All Registrants)

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

Critical Accounting Policies and Estimates

Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. As of September 30, 2025, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2024. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2024 Form 10-K for further information.

Results of Operations by Registrant

Results of Operations — ComEd


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

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

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

The changes in Operating revenues consisted of the following:


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

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

ComEd

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

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Transmission revenues increased for the three months ended September 30, 2025 compared to the same period in 2024, primarily due to higher fully recoverable costs and higher rate base. Transmission revenues decreased for the nine months ended September 30, 2025 as compared to the same period in 2024, primarily due to lower transmission peak load, partially offset by higher fully recoverable costs and the impacts of higher rate base.

Energy Efficiency Revenue. Energy efficiency revenues are under a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred in a given year. Energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenues increased for the three and nine months ended September 30, 2025 as compared to the same periods in 2024, primarily due to increased regulatory asset amortization, which is fully recoverable.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues decreased for the three and nine months ended September 30, 2025 as compared to the same periods in 2024, which primarily reflects decreased mutual assistance revenues associated with storm restoration efforts.

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

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

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

ComEd

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


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

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



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

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

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

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


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

Total increase	$	8	$	38

(a)Reflects ongoing capital expenditures.

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

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

Effective income tax rat****es were 18.2% and 9.1% for the three months ended September 30, 2025 and 2024, respectively, and 18.2% and 9.4% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

PECO

Results of Operations — PECO


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


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

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

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

The changes in Operating revenues consisted of the following:


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

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

PECO

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

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


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

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


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


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

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

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

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)
2025		2024		2025		2024
Residential	2,064		2,359	(12.5)	%	(12.1)	%	28,469	25,779	10.4	%	(0.5)	%
Small commercial & industrial	2,243		1,933	16.0	%	17.5	%	16,046	14,742	8.8	%	1.8	%
Large commercial & industrial	—		1	(100.0)	%	(9.8)	%	14	17	(17.6)	%	(3.8)	%
Transportation	5,081		5,232	(2.9)	%	(2.6)	%	17,759	17,248	3.0	%	0.4	%
Total natural gas retail deliveries(a)	9,388		9,525	(1.4)	%	(1.2)	%	62,288	57,786	7.8	%	0.3	%


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

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

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

Pricing for the three and nine months ended September 30, 2025 compared to the same period in 2024 increased primarily due to electric and gas distribution rates charged to customers.

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

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

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

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

PECO

The increase of $60 million and increase of $175 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting and materials	$	18	$	32
Pension and non-pension postretirement benefit expense	1		3
BSC costs	(3)		(1)
Credit loss expense	(7)		(3)
Storm-related costs(a)	(63)		(29)
Other	(7)		(7)
	(61)		(5)
Regulatory required programs	(11)		1
Total decrease	$	(72)	$	(4)

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

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


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

Total increase	$	7	$	18

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

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

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

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

BGE

Results of Operations — BGE


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

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

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

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

The changes in Operating revenues consisted of the following:


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

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

BGE


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


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

Total	704,376	702,590

Distribution Revenue increased for the three and nine months ended September 30, 2025, compared to the same period in 2024, due to favorable impacts of the multi-year plans.

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

Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue increased for the three and nine months ended September 30, 2025 as compared to the same period in 2024, primarily driven by increases in service application fees.

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

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

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

BGE

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


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

Total (decrease) increase	$	(42)	$	12

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

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

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


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

Total decrease	$	(7)	$	(1)

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

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

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

Effective income tax rates were 21.9% and 8.2% for the three months ended September 30, 2025 and 2024, respectively, and 21.3% and 8.3% for the nine months ended September 30, 2025 and 2024. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

PHI

Results of Operations — PHI

PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services, and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three and nine months ended September 30, 2025 compared to the same periods in 2024. See the Results of Operations for Pepco, DPL, and ACE for additional information.


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

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

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

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

Pepco

Results of Operations — Pepco


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


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

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

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

The changes in Operating revenues consisted of the following:


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

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

Pepco


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

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

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

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

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

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

The increase of $73 million and $134 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

Pepco

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


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		Increase (Decrease)
Maryland multi-year plan reconciliations(a)	$	3	$	27
Labor, other benefits, contracting, and materials	7		3
Storm-related costs	(1)		2
Pension and non-pension postretirement benefits expense	—		1
Credit loss expense	(2)		1
BSC and PHISCO costs	1		(2)


Other(b)	(4)		12
	4		44

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

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

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

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

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


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

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

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

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

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

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

Effective income tax rates were 20.8% and 18.6% for the three months ended September 30, 2025 and 2024, respectively, and 20.9% and 18.6% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

DPL

Results of Operations — DPL


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

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

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

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

The changes in Operating revenues consisted of the following:


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

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

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

DPL

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

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


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

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


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

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

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


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

DPL


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

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

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


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


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

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

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

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

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. During the three and nine months ended September 30, 2025 compared to the same periods in 2024, transmission revenue increased due to increases in underlying costs and capital investments.

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

DPL

deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.

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

The increase of $16 million and $64 million for the three and nine months ended September 30, 2025, respectively, compared to the same period in 2024 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	(Decrease) Increase		Increase (Decrease)
Credit loss expense	$	(2)	$	3


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

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

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


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

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

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

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

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

DPL

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

Effective income tax rates were 23.6% and 20.3% for the three months ended September 30, 2025 and 2024, respectively, and 23.1% and 20.0% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

ACE

Results of Operations — ACE


	Three Months Ended September 30,				Favorable (Unfavorable) Variance			Nine Months Ended September 30,					Favorable (Unfavorable) Variance
	2025		2024				2025			2024
Operating revenues	$	570	$	540	$	30		$	1,328		$	1,280	$	48


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

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

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

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

The changes in Operating revenues consisted of the following:


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

Regulatory required programs	32		44
Total increase	$	30	$	48

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

ACE


	At September 30,
Number of Electric Customers	2025	2024
Residential	509,739	507,060
Small commercial & industrial	62,923	62,761
Large commercial & industrial	2,730	2,848
Public authorities & electric railroads	745	707
Total	576,137	573,376

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

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

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

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

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

The increase of $41 million and $59 million for the three and nine months ended September 30, 2025, respectively, compared to the same periods in 2024 in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

ACE

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


	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting, and materials	$	6	$	3
Storm-related costs	(1)		—
Credit Loss Expense	(1)		—

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

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

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


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

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

Effective income tax rates were 26.1% and 26.5% for the three months ended September 30, 2025 and 2024, respectively and 25.8% and 26.5% for the nine months ended September 30, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Liquidity and Capital Resources (All Registrants)

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

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

Cash Flows from Operating Activities

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

See Note 3 — Regulatory Matters of the 2024 Form 10-K and Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.

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


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

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

Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. Significant operating cash flow impacts for the Registrants for the nine months ended September 30, 2025 and 2024 were as follows:

See Note 14 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.
Changes in collateral depended upon whether the Registrant was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties remained relatively consistent comparing the nine months ended September 30, 2025 to the nine months ended September 30, 2024. See Note 8 — Derivative Financial Instruments for additional information.
See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.
Changes in Pension and non-pension postretirement benefit contributions relates to Exelon's increased contributions to the Qualified Plans during the nine months ended September 30, 2025. See Note 14 — Retirement Benefits of the 2024 Form 10-K for additional information.
Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differing from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $311 million and $266 million for the nine months ended September 30, 2025 and 2024, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $64 million, $27 million, $11 million, and $37 million for the nine months ended September 30, 2025 and $94 million, $34 million, $14 million, and $24 million for the nine months ended September 30, 2024, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the nine months ended September 30, 2025 and 2024. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $215 million and $385 million, respectively. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the nine months ended September 30, 2025, the established pricing has resulted in both a receivable from, and payable to, nuclear-powered generating facilities. The change in receivable from nuclear-powered generating facilities, and the change in payable to nuclear-powered generating facilities, are reflected as a change in accounts receivable and a change in accounts payable and accrued expenses, respectively, within the cash flows from operations.

Cash Flows from Investing Activities

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


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



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

Other investing activities	(16)		(3)		(4)		(3)		—		—		—		—
(Decrease) increase in cash flows from investing activities	$	(986)	$	(354)	$	(346)	$	(181)	$	(207)	$	(16)	$	2	$	(27)

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

Changes in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants.
Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

Cash Flows from Financing Activities

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


Increase (decrease) in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	713	$	493	$	(27)	$	161	$	(188)	$	(54)	$	(48)	$	(86)
Long-term debt, net	479		175		475		(150)		(17)		—		(17)		—
Changes in intercompany money pool	—		—		—		—		(9)		—		—		—
Issuance of common stock	25		—		—		—		—		—		—		—
Dividends paid on common stock	(70)		(28)		(110)		(18)		—		19		13		(32)

Distributions to member	—		—		—		—		1		—		—		—
Contributions from parent/member	—		(9)		(17)		294		64		(68)		(53)		13

Other financing activities	(1)		5		(3)		1		14		11		(2)		—
Increase (decrease) in cash flows from financing activities	$	1,146	$	636	$	318	$	288	$	(135)	$	(92)	$	(107)	$	(105)

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

Changes in short-term borrowings, net**, is driven by repayments on and issuances of notes due in less than 365 days. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants.
Long-term debt, net**, varies due to debt issuances and redemptions each year. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the "Debt" section below for additional information.
Changes in intercompany money pool** are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.
Issuance of common stock** relates to issuances of Exelon common stock during the first quarter of 2025. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 18 — Commitments and Contingencies of the 2024 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.

Debt

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

During the nine months ended September 30, 2025, the following long-term debt was retired and/or redeemed.


Company(a)						Type						Interest Rate									Maturity						Amount
Exelon						Senior Notes						3.95		%							June 15, 2025						$	807

(a)On October 15, 2025, PECO redeemed $350 million of its 3.15% First Mortgage Bonds at maturity.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 2025 and for the fourth quarter of 2025 were as follows:


Period	Declaration Date	Shareholder of Record Date	Dividend Payable Date	Cash per Share(a)
First Quarter 2025	February 12, 2025	February 24, 2025	March 14, 2025	$	0.4000
Second Quarter 2025	April 29, 2025	May 12, 2025	June 13, 2025	$	0.4000
Third Quarter 2025	July 29, 2025	August 11, 2025	September 15, 2025	$	0.4000
Fourth Quarter 2025	October 29, 2025	November 10, 2025	December 15, 2025	$	0.4000

(a)Exelon's Board of Directors approved an updated dividend policy for 2025. The 2025 quarterly dividend will be $0.40 per share.

Credit Matters and Cash Requirements

The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $3.4 billion was available to support additional commercial paper as of September 30, 2025, and of which

no financial institution has more than 6.2% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the nine months ended September 30, 2025 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the 2024 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

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

At-the-Market Programs

On August 4, 2022, Exelon executed an equity distribution agreement (“2022 Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1 billion through August 3, 2025. On May 2, 2025, Exelon executed an additional equity distribution agreement ("2025 Equity Distribution Agreement" and, together with the August 4, 2022 Equity Distribution Agreement, "Equity Distribution Agreements"), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $2.5 billion through May 2, 2028. The 2025 Equity Distribution Agreement replaced the 2022 Equity Distribution Agreement. Exelon has no obligation to offer or sell any shares of Common stock under the 2025 Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the 2025 Equity Distribution Agreement.

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

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

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

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

No amounts have been or will be recorded on Exelon's balance sheet with respect to the equity offerings until the equity forward sale agreements have been settled. Each initial forward sale price is subject to adjustment on a

daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the nine months ended September 30, 2025, approximately 26.7 million shares under the forward sale agreements were not included in the calculation of diluted earnings per share because their effect would have been antidilutive.

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

Incremental Collateral Requirements

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at September 30, 2025 and available credit facility capacity prior to any incremental collateral at September 30, 2025:


	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	26	$	—	$	985
PECO	—		40		595
BGE	—		23		575

Pepco	1		—		235
DPL	—		13		267
ACE	—		—		230

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

Capital Expenditure Spending

As of September 30, 2025, the most recent estimates of capital expenditures for plant additions and improvements for 2025 are as follows:


(In millions)	Transmission	Distribution	Gas	Total(a)
Exelon	N/A	N/A	N/A	$	8,975
ComEd	950	2,250	N/A	3,200
PECO	200	1,375	350	1,950
BGE	650	650	525	1,850
PHI	575	1,475	100	2,150
Pepco	250	750	N/A	1,000
DPL	150	325	75	525
ACE	150	275	N/A	425

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

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

Retirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions.

Exelon’s estimated annual qualified pension contributions will be $275 million in 2025. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

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

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

See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2024 Form 10-K for additional information on pension and OPEB contributions.

Credit Facilities

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

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

Security Ratings

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

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

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

The credit ratings for ComEd, BGE, PHI, Pepco, DPL, and ACE did not change for the nine months ended September 30, 2025. On January 17, 2025, Fitch Ratings affirmed and withdrew the long-term and short-term issuer default ratings along with individual securities ratings of the Registrants for commercial reasons. On February 7, 2025, S&P raised its long-term issuer credit rating for Exelon and PECO from 'BBB+' to 'A-', and raised its rating on Exelon’s senior unsecured debt from ‘BBB’ to 'BBB+'. S&P also affirmed its short-term issuer and commercial paper rating for Exelon and PECO of 'A-2'.

Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of September 30, 2025, are presented in the following table:


	During the Nine Months Ended September 30, 2025				At September 30, 2025
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	578	$	—	$	64
PECO	336		(253)		222
BSC	—		(413)		(284)
PHI Corporate	—		(85)		(64)
PCI	62		—		62


	During the Nine Months Ended September 30, 2025				At September 30, 2025
PHI Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Pepco	$	20	$	(35)	$	—
DPL	48		(1)		—
ACE	—		(46)		—

Shelf Registration Statements

On February 21, 2024, PECO and BGE, as co-registrants, filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. On February 13, 2025, as most recently amended on March 27, 2025, Exelon Corporation and ComEd, as co-registrants filed a shelf registration statement with the SEC ("Exelon and ComEd Shelf Registration") for authorization of up to $12,575 million in additional security registration, to be used to issue Exelon Corporate debt securities and equity securities, as well as ComEd debt securities. The Exelon and ComEd Shelf Registration was declared effective by the SEC on April 8, 2025, and is effective through April 8, 2028. The ability of Exelon Corporation, ComEd, PECO and BGE to sell securities off their corresponding registration Statements, or to access the private placement markets, will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

Pepco, DPL and ACE periodically issue securities through the private placement markets. Pepco, DPL and ACE's ability to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, current financial condition, securities ratings and market conditions.

Regulatory Authorizations

The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:


	At September 30, 2025
	Short-term Financing Authority						Remaining Long-term Financing Authority
Commission	Expiration Date	Amount	Commission			Expiration Date		Amount
ComEd(a)(b)	FERC	December 31, 2025		$	2,500		ICC		January 1, 2027 & May 1, 2027	$	1,593
PECO(c)	FERC	December 31, 2025		1,500			PAPUC		December 31, 2027	1,850
BGE(d)	FERC	December 31, 2025		700			MDPSC		N/A	1,850
Pepco(e)(f)(g)	FERC	December 31, 2025		500			MDPSC / DCPSC		December 31, 2025	100
DPL(e)(h)(i)	FERC	December 31, 2025		500			MDPSC / DEPSC		December 31, 2025	172
ACE(j)	NJBPU	December 31, 2025		350			NJBPU		December 31, 2026	775

(a)On September 8, 2025, ComEd filed an application with the FERC to request a new short-term financing authority for $2.5 billion through December 31, 2027. ComEd expects approval of their application by December 31, 2025.

(b)On September 19, 2025, ComEd filed an application for $2.8 billion in new money long-term debt financing authority from the ICC and expects approval of their application by December 31, 2025.

(c)On September 8, 2025, PECO filed an application with the FERC to request a new short-term financing authority for $1.5 billion through December 31, 2027. PECO expects approval of their application by December 31, 2025.

(d)On September 8, 2025, BGE filed an application with the FERC to request a new short term financing authority for $900 million through December 31, 2027. BGE expects approval of their application by December 31, 2025.

(e)The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DCPSC and DEPSC have an expiration date of December 31, 2025.

(f)On July 17, 2025, Pepco filed an application with the MDPSC and DCPSC to request a new long-term financing authority for $1.1 billion through December 31, 2028. On September 3, 2025, Pepco received approval of their application from the MDSPC. Pepco expects approval of their application from the DCPSC by December 31, 2025.

(g)On September 8, 2025, Pepco filed an application with the FERC to request a new short-term financing authority for $700 million through December 31, 2027. Pepco expects approval of their application by December 31, 2025.

(h)On September 3, 2025, DPL received approval from the MDSPC and DEPSC, respectively, for $700 million in new long-term financing authority, with an effective date of January 1, 2026.

(i)On September 8, 2025, DPL filed an application with the FERC to request a new short-term financing authority for $700 million through December 31, 2027. DPL expects approval of their application by December 31, 2025.

(j)On June 6, 2025, ACE filed an application with the NJBPU to extend their short-term financing authority through January 1, 2028. ACE expects approval of their application by December 31, 2025.

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