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 months ended March 31, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three months ended March 31, 2026 and 2025, see the discussions of Results of Operations by Registrant.


	Three Months Ended March 31,					Favorable (Unfavorable) Variance
		2026			2025
Exelon			$	919		$	908	$	11
ComEd			310			302		8
PECO			278			266		12
BGE			298			260		38
PHI			169			194		(25)
Pepco			68			97		(29)
DPL			77			69		8
ACE			27			31		(4)
Other(a)			(136)			(114)		(22)

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

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income attributable to common shareholders increased by $11 million and diluted earnings per average common share remained relatively consistent to the prior year at $0.90 primarily due to:

Favorable impacts of approved rate increases at ComEd, BGE and PHI;
Absence of Customer Surcharge Credits at PECO;
Higher AFUDC at ComEd; and
Favorable weather at PECO.

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

Timing of distribution earnings at ComEd;
Higher depreciation expense at PECO and PHI;
Higher interest expense at PECO and Exelon Corporate;
Higher credit loss expense at BGE; and
Unfavorable impacts of the Pepco Maryland multi-year plan reconciliation 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 months ended March 31, 2026 compared to the same period in 2025:


	Three Months Ended March 31,
	2026				2025
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net income attributable to common shareholders	$	919	$	0.90	$	908	$	0.90





Change in FERC audit liability (net of taxes of $1)	—		—		2		—

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

Regulatory matters (net of taxes of $4 and $7, respectively)(b)	11		0.01		22		0.02

Adjusted (non-GAAP) operating earnings	$	930	$	0.91	$	932	$	0.92

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2026 and 2025 ranged from 24.0% to 29.0%.

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

(b)Represents the disallowance of certain capitalized costs.

Significant 2026 Transactions and Developments

Distribution Base Rate Case Proceedings

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

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2026. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Completed Distribution Base Rate Case Proceedings


Registrant/Jurisdiction		Filing Date		Service				Requested Revenue Requirement Increase				Approved Revenue Requirement Increase			Approved ROE		Approval Date		Rate Effective Date
ComEd - Illinois		January 17, 2023		Electric				$	1,487			$	1,045		8.905%		December 19, 2024		January 1, 2024
	April 26, 2024 (amended on September 11, 2024)		Electric			$	624			$	623			9.89%		October 31, 2024		January 1, 2025
PECO - Pennsylvania		March 28, 2024		Electric				$	464			$	354		N/A		December 12, 2024		January 1, 2025
		Natural Gas		$	111			$	78
BGE - Maryland		February 17, 2023		Electric				$	313			$	179		9.50%		December 14, 2023		January 1, 2024
		Natural Gas		$	289			$	229			9.45%
Pepco - District of Columbia		April 13, 2023 (amended February 27, 2024)		Electric				$	186			$	123		9.50%		November 26, 2024		January 1, 2025
Pepco - Maryland		May 16, 2023 (amended February 23, 2024)		Electric				$	111			$	45		9.50%		June 10, 2024		April 1, 2024
DPL - Maryland		May 19, 2022		Electric				$	38			$	29		9.60%		December 14, 2022		January 1, 2023
DPL - Delaware		December 15, 2022 (amended September 29, 2023)		Electric				$	39			$	28		9.60%		April 18, 2024		July 15, 2023
	September 20, 2024 (amended September 5, 2025)		Natural Gas			$	37			$	22			9.60%		December 17, 2025		January 1, 2026
ACE - New Jersey		November 21, 2024		Electric				$	109			$	54		9.60%		November 21, 2025		December 1, 2025

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 (amended April 16, 2026)	Electric	$	120	10.50%	Third quarter of 2026
DPL - Delaware	December 9, 2025	Electric	$	45	10.50%	Third quarter of 2027

2026 PECO Distribution Base Rate Filing

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

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

Corporate Alternative Minimum Tax (All Registrants)

On August 16, 2022, the IRA was signed into law and implements a new corporate alternative minimum tax (CAMT) that imposes a 15.0% tax on modified GAAP net income. Corporations will now pay the greater of 15.0% of financial statement pre-tax income (with certain adjustments) or their regular federal tax liability, which is federal taxable income multiplied by the 21.0% federal corporate tax rate. Corporations are entitled to a tax credit (minimum tax credit) to the extent the CAMT liability exceeds the regular tax liability. This amount can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.

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

On February 18, 2026, the U.S. Treasury issued guidance addressing the implementation of CAMT in the form of a notice. The new guidance permits corporate taxpayers to deduct repair and maintenance costs in the calculation of their CAMT liabilities. The notice applies retroactively, permitting Exelon to file amended returns for both 2024 and 2023 to reduce its CAMT liability by $80 million. Pursuant to the TMA, Exelon received reimbursement from Constellation for $235 million due to the reduction in the amount of Constellation's tax credits needed to offset Exelon's CAMT liability on its amended returns. See Note 6 – Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

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

Other Key Business Drivers and Management Strategies

The following discussion of other key business drivers and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business in the 2025 Form 10-K, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the 2025 Form 10-K, and Note 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

Maryland Utility Relief Act

On April 13, 2026, the Maryland Utility RELIEF Act (Utility RELIEF Act) was passed through the Maryland General Assembly and awaits the Governor’s signature to become law. If and when the Utility RELIEF Act becomes law, it will modify the regulatory framework and rules governing recovery of certain costs in utility ratemaking in Maryland. Exelon, BGE, Pepco, and DPL are in the process of assessing the potential impacts of the pending legislation.

PJM Cost Allocation Methodology (All Registrants).

On March 6, 2026, FERC issued an order requiring the removal of the de minimis threshold exemption in the calculation of the cost responsibility of certain transmission reliability upgrade costs allocated to the rate zones of PJM transmission owners, including the Utility Registrants. FERC further ordered PJM to recalculate historical cost allocations for the period beginning June 18, 2015, and to pass through additional charges or payments to PJM customers, including Utility Registrants, as applicable, with interest within 90 days. On April 29, 2026, the time for those calculations was extended until further order from FERC. The Utility Registrants expect to recover any incremental charges incurred or reimburse any payments received through prospective electric customer rates. On April 6, 2026, a number of parties filed petitions for rehearing or clarification.

The final impacts of the decision cannot be predicted and the results, while not reasonably estimable at this time, could be material to the 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 March 31, 2026, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2025. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2025 Form 10-K for further information.

Results of Operations by Registrant

Results of Operations — ComEd


	Three Months Ended March 31,					(Unfavorable) Favorable Variance
		2026			2025
Operating revenues			$	1,913		$	2,065	$	(152)
Operating expenses
Purchased power			451			689		238
Operating and maintenance			438			423		(15)
Depreciation and amortization			404			380		(24)
Taxes other than income taxes			105			99		(6)
Total operating expenses			1,398			1,591		193

Operating income			515			474		41
Other income and (deductions)
Interest expense, net			(135)			(128)		(7)
Other, net			31			21		10
Total other income and (deductions)			(104)			(107)		3
Income before income taxes			411			367		44
Income taxes			101			65		(36)
Net income			$	310		$	302	$	8

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net Income increased by $8 million as compared to the same period in 2025 primarily due to higher distribution and transmission rate base driven by incremental investments to serve customers and higher AFUDC, offset by the timing of distribution earnings.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2026
	(Decrease) Increase
Distribution	$	(8)
Transmission	20
Energy efficiency	8
Other	3
	23
Regulatory required programs	(175)
Total decrease	$	(152)

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

Distribution Revenue. Starting in 2024, distribution revenues are under a MRP. The MRP requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenues decreased for the three months ended March 31, 2026 as compared to the same period in 2025, primarily due to lower fully recoverable costs.

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

ComEd

for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to higher fully recoverable costs and 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 months ended March 31, 2026 as compared to the same periods in 2025, primarily due to higher fully recoverable costs.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues increased for the three months ended March 31, 2026 as compared to the same periods in 2025, which primarily reflects increased mutual assistance revenues associated with storm restoration efforts.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs. 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, this is treated as a pass through for ComEd and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover costs from customers.

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

The decrease of $238 million for the three months ended March 31, 2026 compared to the same period in 2025 in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended March 31, 2026
	Increase (Decrease)
Labor, other benefits, contracting, and materials	$	21
Storm-related costs	12
BSC costs	3
Pension and non-pension postretirement benefits expense	2



Other(a)	(20)
	18
Regulatory required programs	(3)
Total increase	$	15

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

ComEd

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


	Three Months Ended March 31, 2026
	Increase
Depreciation and amortization(a)	$	15
Regulatory asset amortization	9

Total increase	$	24

(a)Reflects ongoing capital expenditures.

Other, net increased $10 million for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to higher AFUDC equity.

Effective income tax rat****es were 24.6% and 17.7% for the three months ended March 31, 2026 and 2025, 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 March 31,					Favorable (Unfavorable) Variance
		2026			2025
Operating revenues			$	1,492		$	1,333	$	159
Operating expenses
Purchased power and fuel			612			502		(110)
Operating and maintenance			337			327		(10)
Depreciation and amortization			121			109		(12)
Taxes other than income taxes			69			60		(9)
Total operating expenses			1,139			998		(141)

Operating income			353			335		18
Other income and (deductions)
Interest expense, net			(71)			(63)		(8)
Other, net			11			8		3
Total other income and (deductions)			(60)			(55)		(5)
Income before income taxes			293			280		13
Income taxes			15			14		(1)


Net income			$	278		$	266	$	12

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income increased by $12 million due to an increase in revenue as a result of the absence of surcharge credits to customers, favorable weather relative to the same period last year, and tax repairs, some of which is timing, partially offset by an increase in depreciation and interest expense.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2026
	Increase (Decrease)
		Electric		Gas		Total
Weather		$	8	$	8	$	16
Volume		(4)		1		(3)
Pricing		5		2		7
Transmission		12		—		12
Other(a)		25		4		29
		46		15		61
Regulatory required programs		79		19		98
Total increase		$	125	$	34	$	159

(a)Other revenues increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended March 31, 2026, compared to the same period in 2025, Operating revenues related to weather increased due to favorable weather conditions in PECO's service territory.

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

PECO

PECO’s service territory for the three months ended March 31, 2026, compared to the same period in 2025, and normal weather consisted of the following:


	Three Months Ended March 31,				% Change
PECO Service Territory	2026	2025	Normal	2026 vs. 2025	2026 vs. Normal




Heating Degree-Days	2,399	2,351		2,359	2.0	%	1.7	%
Cooling Degree-Days	10	1		1	900.0	%	900.0	%

Volume. Electric volume, exclusive of the effects of weather, for the three months ended March 31, 2026 compared to the same period in 2025, remained relatively consistent. Natural gas volume for the three months ended March 31, 2026, compared to the same period in 2025, remained relatively consistent.


Electric Retail Deliveries to Customers (in GWhs)		Three Months Ended March 31,		% Change	Weather - Normal % Change(b)
	2026	2025
Residential			3,952	3,859	2.4	%	0.1	%
Small commercial & industrial			2,010	1,946	3.3	%	1.0	%
Large commercial & industrial			3,132	3,425	(8.6)	%	(10.0)	%
Public authorities & electric railroads			176	189	(6.9)	%	(7.0)	%
Total electric retail deliveries(a)			9,270	9,419	(1.6)	%	(3.5)	%


	At March 31,
Number of Electric Customers	2026	2025
Residential	1,544,881	1,540,453
Small commercial & industrial	154,634	155,131
Large commercial & industrial	3,149	3,151
Public authorities & electric railroads	10,108	10,703
Total	1,712,772	1,709,438

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

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


Natural Gas Deliveries to Customers (in mmcf)		Three Months Ended March 31,		% Change	Weather - Normal % Change(b)
	2026	2025
Residential			22,436	21,834	2.8	%	(0.9)	%
Small commercial & industrial			11,351	10,405	9.1	%	6.2	%
Large commercial & industrial			(10)	12	(183.3)	%	(20.0)	%
Transportation			7,142	7,242	(1.4)	%	(2.2)	%
Total natural gas deliveries(a)			40,919	39,493	3.6	%	0.7	%


	At March 31,
Number of Natural Gas Customers	2026	2025
Residential	511,085	509,773
Small commercial & industrial	44,642	44,869
Large commercial & industrial	7	7
Transportation	606	623
Total	556,340	555,272

PECO

(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 months ended March 31, 2026, compared to the same period in 2025, remained relatively consistent.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the three months ended March 31, 2026, compared to the same period in 2025, increased primarily due to increases in the underlying costs and capital investments.

Other Revenue primarily includes revenue related to late payment charges. Other revenue for the three months ended March 31, 2026, compared to the same period in 2025, increased primarily due to the absence of electric surcharge credits to customers recognized in 2025.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for PECO and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover costs from customers.

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

The increase of $110 million for the three months ended March 31, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended March 31, 2026
	Increase (Decrease)
Labor, other benefits, contracting and materials	$	17
BSC costs	6
Pension and non-pension postretirement benefit expense	1
Credit loss expense	(2)
Storm-related costs	(6)
Other	13
	29
Regulatory required programs	(19)
Total increase	$	10

PECO

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


	Three Months Ended March 31, 2026
	Increase
Depreciation and amortization(a)	$	12


Total increase	$	12

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

Effective income tax rates were 5.1% and 5.0% for the three months ended March 31, 2026 and 2025, 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 March 31,				Favorable (Unfavorable) Variance
	2026		2025
Operating revenues	$	1,828	$	1,554	$	274
Operating expenses
Purchased power and fuel	808		609		(199)
Operating and maintenance	327		305		(22)
Depreciation and amortization	167		164		(3)
Taxes other than income taxes	104		96		(8)
Total operating expenses	1,406		1,174		(232)

Operating income	422		380		42
Other income and (deductions)
Interest expense, net	(62)		(58)		(4)
Other, net	17		9		8
Total other income and (deductions)	(45)		(49)		4
Income before income taxes	377		331		46
Income taxes	79		71		(8)
Net income	$	298	$	260	$	38

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025**.** Net income increased $38 million primarily due to approved distribution rates and a decrease in various operating expenses, partially offset by an increase in credit loss expense.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2026
	Increase (Decrease)
	Electric		Gas		Total
Distribution	$	4	$	22	$	26
Transmission	(2)		—		(2)
Other	9		2		11
	11		24		35
Regulatory required programs	223		16		239
Total increase	$	234	$	40	$	274

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.


	At March 31,
Number of Electric Customers	2026	2025
Residential	1,226,941	1,220,769
Small commercial & industrial	115,253	115,359
Large commercial & industrial	13,372	13,302
Public authorities & electric railroads	251	258
Total	1,355,817	1,349,688

BGE


	At March 31,
Number of Natural Gas Customers	2026	2025
Residential	663,324	661,195
Small commercial & industrial	37,735	37,945
Large commercial & industrial	6,421	6,380

Total	707,480	705,520

Distribution Revenue increased for the three months ended March 31, 2026, compared to the same period in 2025, due to favorable impacts of the multi-year plans.

Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue increased for the three months ended March 31, 2026 as compared to the same period in 2025, primarily driven by increases in late payment charges.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for BGE and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover costs from customers.

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

The increase of $199 million for the three months ended March 31, 2026, compared to the same period in 2025, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended March 31, 2026
	Increase (Decrease)
Credit loss expense	$	11
BSC costs	3
Pension and non-pension postretirement benefits expense	(5)
Labor, other benefits, contracting and materials	(16)

Other	1
	(6)
Regulatory required programs(a)	28

Total increase	$	22

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

BGE

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


	Three Months Ended March 31, 2026
	Increase (Decrease)
Depreciation and amortization	$	9
Regulatory required programs(a)	3
Regulatory asset amortization	(9)

Total increase	$	3

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

Taxes other than income taxes increased $8 million for the three months ended March 31, 2026, compared to the same period in 2025, primarily due to increased property taxes.

Effective income tax rates were 21.0% and 21.5% for the three months ended March 31, 2026 and 2025. 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 months ended March 31, 2026 compared to the same period in 2025. See the Results of Operations for Pepco, DPL, and ACE for additional information.


	Three Months Ended March 31,					(Unfavorable) Favorable Variance
		2026			2025
PHI			$	169		$	194	$	(25)
Pepco			68			97		(29)
DPL			77			69		8
ACE			27			31		(4)
Other(a)			(3)			(3)		—

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

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net Income decreased by $25 million primarily due to unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, an increase in depreciation expense, storm costs, and interest expense, partially offset by approved transmission rates, favorable weather conditions at DPL and approved Delaware electric DSIC and natural gas rates.

Pepco

Results of Operations — Pepco


	Three Months Ended March 31,					Favorable (Unfavorable) Variance
2026			2025
Operating revenues	$	989		$	859	$	130


Operating expenses
Purchased power	411			318		(93)
Operating and maintenance	218			159		(59)
Depreciation and amortization	114			105		(9)
Taxes other than income taxes	118			113		(5)
Total operating expenses	861			695		(166)
Loss on sale of assets	—			(1)		1
Operating income	128			163		(35)
Other income and (deductions)
Interest expense, net	(55)			(52)		(3)
Other, net	11			11		—
Total other income and (deductions)	(44)			(41)		(3)
Income before income taxes	84			122		(38)
Income taxes	16			25		9
Net income	$	68		$	97	$	(29)

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net Income decreased by $29 million primarily due to unfavorable impacts of the Pepco Maryland multi-year plan reconciliation and related disallowance of capitalized costs, and increases in depreciation and interest expense.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2026
	Increase
Distribution	$	2
Transmission	3
Other	6
	11
Regulatory required programs	119
Total increase	$	130

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.


	At March 31,
Number of Electric Customers in Maryland	2026	2025
Residential	560,946	557,672
Small commercial & industrial	30,637	30,555
Large commercial & industrial	19,058	18,986
Public authorities & electric railroads	181	177
Total	610,822	607,390

Pepco

Distribution Revenue increased for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to favorable impacts of the District of Columbia multi-year plans and customer growth in Maryland.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2026, compared to the same period in 2025, primarily due to increases in underlying costs and capital investments.

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

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service. For customers that choose to purchase electric generation from competitive suppliers, this is treated as a pass through for Pepco and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the costs from customers.

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

The increase of $93 million for the three months ended March 31, 2026, respectively, compared to the same period in 2025, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended March 31, 2026
	Increase (Decrease)
Maryland multi-year plan reconciliation(a)	$	26
Labor, other benefits, contracting, and materials	9
BSC and PHISCO costs	5
Storm-related costs	1


Other	(3)
	38

Regulatory required programs(b)	21
Total increase	$	59

(a)Reflects unfavorable impacts of the Pepco Maryland multi-year plan reconciliation. See Note 2 — Regulatory Matters for additional information.

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

Pepco

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


	Three Months Ended March 31, 2026
	Increase
Depreciation and amortization(a)	$	6
Regulatory asset amortization	1
Regulatory required programs(b)	2
Total increase	$	9

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

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

Effective income tax rates were 19.0% and 20.5% for the three months ended March 31, 2026 and 2025, 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 March 31,					Favorable (Unfavorable) Variance
2026			2025
Operating revenues	$	622		$	548	$	74
Operating expenses
Purchased power and fuel	289			247		(42)
Operating and maintenance	118			106		(12)
Depreciation and amortization	66			63		(3)
Taxes other than income taxes	26			21		(5)
Total operating expenses	499			437		(62)

Operating income	123			111		12
Other income and (deductions)
Interest expense, net	(27)			(25)		(2)
Other, net	4			4		—
Total other income and (deductions)	(23)			(21)		(2)
Income before income taxes	100			90		10
Income taxes	23			21		(2)
Net income	$	77		$	69	$	8

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income increased by $8 million primarily due to approved Delaware electric DSIC and natural gas rates, favorable weather conditions at Delaware electric and natural gas service territories, partially offset by an increase in storm costs.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2026
	Increase (Decrease)
	Electric		Gas		Total
Weather	$	3	$	2	$	5
Volume	1		(1)		—
Distribution	6		10		16
Transmission	2		—		2
Other	—		—		—
	12		11		23
Regulatory required programs	33		18		51
Total increase	$	45	$	29	$	74

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 demand. During the three months ended March 31, 2026 compared to the same period in 2025, Operating revenues related to weather increased due to favorable weather conditions in DPL's Delaware electric and natural gas service territories.

DPL

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 months ended March 31, 2026, compared to same period in 2025 and normal weather consisted of the following:


	Three Months Ended March 31,			% Change
Delaware Electric Service Territory	2026	2025	Normal	2026 vs. 2025		2026 vs. Normal
Heating Degree-Days	2,531	2,399	2,406	5.5	%	5.2	%
Cooling Degree-Days	9	9	1	—	%	800.0	%


	Three Months Ended March 31,			% Change
Delaware Natural Gas Service Territory	2026	2025	Normal	2026 vs. 2025		2026 vs. Normal
Heating Degree-Days	2,531	2,399	2,449	5.5	%	3.3	%

Volume, exclusive of the effects of weather, remained relatively consistent for the three months ended March 31, 2026 compared to the same period in 2025.


Electric Retail Deliveries to Delaware Customers (in GWhs)	Three Months Ended March 31,			% Change		Weather - Normal % Change(b)
2026		2025
Residential	974		930	4.7	%	1.1	%
Small commercial & industrial	367		354	3.7	%	1.8	%
Large commercial & industrial	687		690	(0.4)	%	(1.0)	%
Public authorities & electric railroads	7		7	—	%	(2.8)	%
Total electric retail deliveries(a)	2,035		1,981	2.7	%	0.5	%


	At March 31,
Number of Total Electric Customers (Maryland and Delaware)	2026	2025
Residential	496,074	491,907
Small commercial & industrial	65,604	64,999
Large commercial & industrial	1,288	1,251
Public authorities & electric railroads	628	617
Total	563,594	558,774

(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 March 31,			% Change		Weather - Normal % Change(b)
2026		2025
Residential	4,678		4,590	1.9	%	(2.3)	%
Small commercial & industrial	2,128		1,970	8.0	%	3.0	%
Large commercial & industrial	429		428	0.2	%	0.2	%
Transportation	2,027		2,106	(3.8)	%	(6.1)	%
Total natural gas deliveries(a)	9,262		9,094	1.8	%	(1.9)	%

DPL


	At March 31,
Number of Delaware Natural Gas Customers	2026	2025
Residential	132,419	131,716
Small commercial & industrial	10,285	10,254
Large commercial & industrial	14	15
Transportation	159	161
Total	142,877	142,146

(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 months ended March 31, 2026 compared to the same period in 2025 primarily due to Delaware natural gas rates that became effective in 2025 & electric DSIC rates that became effective in 2026.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. During the three months ended March 31, 2026 compared to the same period in 2025, transmission revenue remained relatively consistent.

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

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service. For customers that choose to purchase electric generation or natural gas from competitive suppliers, this is treated as a pass through for DPL and therefore, financial results are not impacted if customers purchase electricity or natural gas supply from these alternative suppliers. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover costs from customers.

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

The increase of $42 million for the three months ended March 31, 2026, respectively, compared to the same period in 2025 in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended March 31, 2026
	Increase (Decrease)
Storm-related costs	$	5


Labor, other benefits, contracting, and materials	2
Credit loss expense	(2)

	5
Regulatory required programs(a)	7
Total increase	$	12

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

DPL

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


	Three Months Ended March 31, 2026
	Increase
Depreciation and amortization(a)	$	2
Regulatory asset amortization	—
Regulatory required programs(b)	1
Total increase	$	3

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

(b)Reflects the cost recovery associated with EmPOWER Maryland. Please refer to 2025 10-K Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information

Taxes other than income taxes increased by $5 million for the three months ended March 31, 2026, respectively, compared to the same period in 2025 primarily due to an increase in property taxes.

Effective income tax rates were 23.0% and 23.3% for the three months ended March 31, 2026 and 2025, 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 March 31,				Favorable (Unfavorable) Variance
	2026		2025
Operating revenues	$	421	$	373	$	48


Operating expenses
Purchased power	205		157		(48)
Operating and maintenance	93		90		(3)
Depreciation and amortization	65		64		(1)
Taxes other than income taxes	2		2		—
Total operating expenses	365		313		(52)

Operating income	56		60		(4)
Other income and (deductions)
Interest expense, net	(22)		(21)		(1)
Other, net	2		3		(1)
Total other income and (deductions)	(20)		(18)		(2)
Income before income taxes	36		42		(6)
Income taxes	9		11		2
Net income	$	27	$	31	$	(4)

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. Net income decreased by $4 million primarily due to an increase in storms costs and depreciation expense, partially offset by an increase in approved transmission rates.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2026
	(Decrease) Increase
Distribution	$	(1)
Transmission	3

	2
Regulatory required programs	46
Total increase	$	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 March 31,
Number of Electric Customers	2026	2025
Residential	510,569	508,354
Small commercial & industrial	63,174	62,861
Large commercial & industrial	2,660	2,824
Public authorities & electric railroads	756	723
Total	577,159	574,762

Distribution Revenue remained relatively consistent for the three months ended March 31, 2026 compared to the same period in 2025.

Transmission Revenues Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2026 compared to the same period in 2025 primarily due to increases in underlying costs and capital investment.

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

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service. For customers that choose to purchase electric generation from competitive suppliers, this is treated as a pass through for ACE and therefore, financial results are not impacted if customers purchase electricity supply from these alternative suppliers. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover costs from customers.

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

The increase of $48 million for the three months ended March 31, 2026, respectively, compared to the same period in 2025 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 March 31, 2026
	(Decrease) Increase

Storm-related costs	$	4
Credit Loss Expense	(2)


Other	(1)
	1

Regulatory required programs	2
Total increase	$	3

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


	Three Months Ended March 31, 2026
	Increase (Decrease)
Depreciation and amortization(a)	$	2
Regulatory asset amortization	4
Regulatory required programs	(5)
Total increase	$	1

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

Effective income tax rates were 25.0% and 26.2% for the three months ended March 31, 2026 and 2025, 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 2 — Regulatory Matters of the 2025 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 three months ended March 31, 2026 and 2025 by Registrant:


Increase (decrease) in cash flows from operating activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income (loss)	$	11	$	8	$	12	$	38	$	(25)	$	(29)	$	8	$	(4)
Adjustments to reconcile net income to cash:
Non-cash operating activities	148		(17)		288		148		88		57		18		32

Collateral received, net	1		47		(12)		3		(37)		(22)		(2)		(11)
Income taxes	(203)		(43)		(294)		(147)		(70)		(43)		(16)		(24)
Pension and non-pension postretirement benefit contributions	(54)		(31)		(3)		(6)		(10)		—		(1)		(10)
Regulatory assets and liabilities, net	(415)		(426)		(82)		57		23		22		1		(4)
Changes in working capital and other assets and liabilities	1,036		847		(23)		(8)		105		81		22		3
Increase (decrease) in cash flows from operating activities	$	524	$	385	$	(114)	$	85	$	74	$	66	$	30	$	(18)

Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below.

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

See Note 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 three months ended March 31, 2026 to the three months ended March 31, 2025. 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 three months ended March 31, 2026. See Note 12 — Retirement Benefits of the 2025 Form 10-K for additional information.
Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differing from the recovery period of those costs. ComEd recognized a reduction in regulatory liabilities of $236 million and a reduction in regulatory assets of $162 million related to carbon mitigation credits for the three months ended March 31, 2026 and 2025, respectively. Included within the change in 2026 are payments for CMC nuclear production tax credits, which relate to a decrease in Accounts Receivable. ComEd's energy efficiency program recognized changes of $84 million for the three months ended March 31, 2026 and 2025, respectively. Additionally, ComEd recognized changes in the distributed generation rebates programs of $29 million and $19 million for the three months ended March 31, 2026 and 2025, respectively. Also included within the changes is energy efficiency and demand response programs spend for DPL and ACE of $1 million and $15 million for the three

months ended March 31, 2026 and $3 million, and $5 million for the three months ended March 31, 2025, respectively. BGE and Pepco had no energy efficiency and demand response programs spend recorded to the regulatory asset for the three months ended March 31, 2026 and $22 million and $6 million for three months ended March 31, 2025. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the three months ended March 31, 2026 and 2025.

Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $922 million and $1,036 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 three months ended March 31, 2026, the established pricing has resulted in ComEd receiving payments from nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in Accounts receivable. This change corresponds to a decrease in the Carbon mitigation credit regulatory liability. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the three months ended March 31, 2026 and 2025 by Registrant:


(Decrease) increase in cash flows from investing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	(412)	$	(295)	$	(45)	$	(31)	$	(45)	$	(45)	$	9	$	(17)



Proceeds from sales of assets	—		—		—		—		—		—		—		—
Changes in intercompany money pool	—		—		(5)		—		—		—		12		—

Other investing activities	(2)		(1)		(3)		1		—		—		—		—
(Decrease) increase in cash flows from investing activities	$	(414)	$	(296)	$	(53)	$	(30)	$	(45)	$	(45)	$	21	$	(17)

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

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

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the three months ended March 31, 2026 and 2025 by Registrant:


(Decrease) increase in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	828	$	(265)	$	192	$	(62)	$	37	$	(30)	$	29	$	38
Long-term debt, net	(1,305)		—		—		—		(80)		(30)		(50)		—
Changes in intercompany money pool	—		—		—		—		29		—		—		(12)
Issuance of common stock	(173)		—		—		—		—		—		—		—
Dividends paid on common stock	(27)		(15)		—		(16)		—		2		(4)		(5)

Distributions to member	—		—		—		—		(7)		—		—		—
Contributions from parent/member	—		169		4		—		(77)		(18)		(54)		(3)

Other financing activities	20		—		—		—		1		2		—		1
(Decrease) increase in cash flows from financing activities	$	(657)	$	(111)	$	196	$	(78)	$	(97)	$	(74)	$	(79)	$	19

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

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 16 — Commitments and Contingencies of the 2025 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.

Debt

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

During the three months ended March 31, 2026, no long-term debt was retired and/or redeemed. Exelon repaid $750 million of its Senior Notes on the maturity date of April 15, 2026.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the three months ended March 31, 2026 and for the second quarter of 2026 were as follows:


Period	Declaration Date	Shareholder of Record Date	Dividend Payable Date	Cash per Share(a)
First Quarter 2026	February 12, 2026	March 2, 2026	March 13, 2026	$	0.4200
Second Quarter 2026	April 28, 2026	June 4, 2026	June 15, 2026	$	0.4200

(a)Exelon's Board of Directors approved an updated dividend policy for 2026. The 2026 quarterly dividend will be $0.42 per share.

Credit Matters and Cash Requirements

The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $3.8 billion was available to support additional commercial paper as of March 31, 2026, and of which no financial institution has more than 6.2% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the three months ended March 31, 2026 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 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 2025 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

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

At-the-Market Program

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

In the first quarter of 2026, Exelon entered into various forward sale agreements under the 2025 ATM programs. The forward sale agreements require Exelon to, at its election prior to the maturity date, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements. The following forward sale agreements were entered into under Exelon’s ATM program in the first quarter of 2026:


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

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


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

No amounts have been or will be recorded on Exelon's balance sheet with respect to the equity offerings until the equity forward sale agreements have been settled. Each initial forward sale price is subject to adjustment on a daily basis based on a floating interest rate factor and will decrease by other fixed amounts specified in the agreements. Until settlement of the equity forward, earnings per share dilution resulting from the agreement, if any, will be determined under the treasury stock method. For the three months ended March 31, 2026, approximately 26.5 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, $1.0 billion of Common stock remained available for sale pursuant to the ATM program as of March 31, 2026.

Incremental Collateral Requirements

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at March 31, 2026 and available credit facility capacity prior to any incremental collateral at March 31, 2026:


	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	19	$	—	$	936
PECO	4		38		595
BGE	5		20		573

Pepco	—		—		225
DPL	—		23		253
ACE	—		—		299

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

Capital Expenditure Spending

As of March 31, 2026, the most recent estimates of capital expenditures for plant additions and improvements for 2026 are as follows:


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

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

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

Retirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $325 million in 2026. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

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

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

See Note 12 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2025 Form 10-K for additional information on pension and OPEB contributions.

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 the Registrants did not change for the three months ended March 31, 2026. On April 30, 2026, S&P lowered its long-term issuer credit rating and senior unsecured debt rating for BGE from 'A' to 'A-'. S&P also lowered its short-term and commercial paper rating for BGE from 'A-1' to '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 March 31, 2026, are presented in the following table:


	During the Three Months Ended March 31, 2026				At March 31, 2026
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	502	$	—	$	373
PECO	343		(63)		5
BSC	—		(461)		(322)
PHI Corporate	—		(134)		(120)
PCI	64		—		64


	During the Three Months Ended March 31, 2026				At March 31, 2026
PHI Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Pepco	$	6	$	—	$	—
DPL	—		(6)		—
ACE	—		—		—

Shelf Registration Statements

On February 13, 2025, Exelon and ComEd filed a combined shelf registration statement on Form S-3 registering $12.6 billion in aggregate amount of securities, which was declared effective by the SEC on April 8, 2025. The shelf registration statement may be used to issue Exelon debt and equity securities as well as ComEd debt securities through the expiration date of April 8, 2028. On February 21, 2024, PECO and BGE filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. The ability of Exelon, ComEd, PECO and BGE to sell securities off their corresponding registration statements will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings, and market conditions.

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

Regulatory Authorizations

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


	At March 31, 2026
	Short-term Financing Authority						Remaining Long-term Financing Authority
Commission	Expiration Date	Amount	Commission			Expiration Date		Amount
ComEd	FERC	December 31, 2027		$	2,500		ICC		January 1, 2027, May 1, 2027, & January 1, 2029	$	4,393
PECO	FERC	December 31, 2027		1,500			PAPUC		December 31, 2027	1,850
BGE	FERC	December 31, 2027		900			MDPSC		N/A	1,850
Pepco(a)	FERC	December 31, 2027		700			MDPSC / DCPSC		December 31, 2028	930
DPL(a)	FERC	December 31, 2027		700			MDPSC / DEPSC		December 31, 2028	625
ACE	NJBPU	January 1, 2028		350			NJBPU		December 31, 2026	525

(a)The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DCPSC and DEPSC have an expiration date of December 31, 2028.

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