Exelon Corporation

05/06/2026 | Press release | Distributed by Public on 05/06/2026 12:19

Quarterly Report for Quarter Ending March 31, 2026 (Form 10-Q)

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 rates 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.
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 remained relatively consistent.
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
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(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
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(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
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(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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