EXELON CORP 10-Q

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Dollars in millions except per share data, unless otherwise noted) Exelon Executive Overview Exelon is a utility services holding company engaged in the energy transmission and distribution businesses through it's six reportable segments: ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments. Exelon’s consolidated financial information includes the results of its seven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. Financial Results of Operations GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders by Registrant for the three months ended March 31, 2025 compared to the same period in 2024. For additional information regarding the financial results for the three months ended March 31, 2025 and 2024, see the discussions of Results of Operations by Registrant. Three Months Ended March 31, Favorable (Unfavorable) Variance 2025 2024 Exelon $ 908 $ 658 $ 250 ComEd 302 193 109 PECO 266 149 117 BGE 260 264 (4) PHI 194 168 26 Pepco 97 75 22 DPL 69 66 3 ACE 31 29 2 Other (a) (114) (116) 2 __________ (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, 2025 Compared to Three Months Ended March 31, 2024. Net income attributable to common shareholders increased by $250 million and diluted earnings per average common share increased to $0.90 in 2025 from 0.66 in 2024 primarily due to: • Timing of distribution earnings at ComEd; • Favorable impacts of rate increases at ComEd, PECO, BGE and PHI; • Normal weather at PECO compared to unfavorable weather in the prior period; • Timing of income tax expense at PECO; and • Higher return on regulatory assets at ComEd. The increases were partially offset by: 88 Table of Contents • Higher interest expense at PECO, BGE and PHI; and • Lower transmission peak load due to lower energy demand at ComEd. Adjusted (non-GAAP) operating earnings. In addition to Net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-over-year operating results and provide an indication of Exelon’s baseline operating performance excluding items 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, 2025 compared to the same period in 2024: Three Months Ended March 31, 2025 2024 (In millions, except per share data) Earnings per Diluted Share Earnings per Diluted Share Net income attributable to common shareholders $ 908 $ 0.90 $ 658 $ 0.66 Regulatory matters (net of taxes of $7) (a) 22 0.02 — — Change in FERC audit liability (net of taxes of $1 and $9, respectively) 2 — 27 0.03 Cost management charge (net of taxes of $0) (b) (1) — — — Adjusted (non-GAAP) operating earnings $ 932 $ 0.92 $ 685 $ 0.68 __________ Note: Amounts may not sum due to rounding. Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net income attributable to common shareholders and Adjusted (non-GAAP) operating earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2025 and 2024 ranged from 24.0% to 29.0%. (a) Represents the probable disallowance of certain capitalized costs. (b) Primarily represents severance and reorganization costs related to cost management. Significant 2025 Transactions and Developments Distribution Base Rate Case Proceedings The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements. The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2025. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 89 Table of Contents 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 (e) December 12, 2024 January 1, 2025 Natural Gas $ 111 $ 78 BGE - Maryland February 17, 2023 Electric $ 313 $ 179 9.50 % December 14, 2023 January 1, 2024 Natural Gas $ 289 $ 229 9.45 % Pepco - District of Columbia April 13, 2023 (amended February 27, 2024) Electric $ 186 $ 123 9.50% November 26, 2024 January 1, 2025 Pepco - Maryland May 16, 2023 (amended February 23, 2024) Electric $ 111 $ 45 9.50 % June 10, 2024 April 1, 2024 DPL - Maryland May 19, 2022 Electric $ 38 $ 29 9.60 % December 14, 2022 January 1, 2023 DPL - Delaware December 15, 2022 (amended September 29, 2023) Electric $ 39 $ 28 9.60 % April 18, 2024 July 15, 2023 ACE - New Jersey February 15, 2023 (amended August 21, 2023) Electric $ 92 $ 45 9.60 % November 17, 2023 December 1, 2023 90 Table of Contents Pending Distribution Base Rate Case Proceedings Registrant/Jurisdiction Filing Date Service Requested Revenue Requirement Increase Requested ROE Expected Approval Timing DPL - Delaware September 20, 2024 (amended February 28, 2025) Natural Gas $ 42 10.65 % First quarter of 2026 ACE - New Jersey November 21, 2024 Electric 109 10.70% Fourth quarter of 2025 Transmission Formula Rates For 2025, the following total increase was included in the Utility Registrant's electric transmission formula rate update. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. Registrant Initial Revenue Requirement Increase Annual Reconciliation Increase Total Revenue Requirement Increase Allowed Return on Rate Base Allowed ROE BGE $ 21 $ 21 $ 35 7.53 % 10.50 % ComEd's FERC Audit The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extended back to January 1, 2017. On July 27, 2023, FERC published a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations, including a suggestion that refunds may be due to customers for amounts collected in previous years. ComEd responded to that report and on August 28, 2023, ComEd filed a formal notice of the issues it contested within the audit report. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings and set the matter for a trial-type hearing. That hearing process was held in abeyance while a formal settlement process, which began in February 2024, took place. On July 30, 2024, ComEd reached an agreement in principle on the contested overhead allocation finding. As a result of the settlement process, ComEd recorded a charge for the probable disallowance of $70 million of certain currently capitalized construction costs to operating expenses, which are not expected to be recovered in future rates. The existing loss estimate was reflected in Exelon and ComEd's financial statements as of December 31, 2024. ComEd and FERC staff jointly filed the settlement agreement with FERC for approval on February 11, 2025. The settlement was approved by FERC on April 4, 2025. 91 Table of Contents Other Key Business Drivers and Management Strategies The following discussion of other key business drivers and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business in the 2024 Form 10-K, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the 2024 Form 10-K, and Note 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters. Allocation of Income Taxes to Regulated Utilities (All Registrants) In Q2 2024, the IRS issued a series of PLRs, to another taxpayer, providing guidance with respect to the application of the tax normalization rules to the allocation of consolidated tax benefits among the members of a consolidated group associated with NOLC for ratemaking purposes. The rulings provide that for ratemaking purposes the tax benefit of NOLC should be reflected on a separate company basis not taking into consideration the utilization of losses by other affiliates. A PLR issued to another taxpayer may not be relied on as precedent. For the Registrants, except for PECO, the methodology prescribed by the IRS in these PLRs could result in a reduction of the regulatory liability established for EDITs arising from the TCJA corporate tax rate change that is 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 purpose. The Utility Registrants will record the impact, if any, upon receiving the PLR from the IRS. Legislative and Regulatory Developments Infrastructure Investment and Jobs Act On November 15, 2021, President Biden signed the $1.2 trillion IIJA into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. The Registrants continue to evaluate programs under the legislation and consider possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA. The Trump Administration has issued numerous Executive Orders (EOs), including the Unleashing American Energy Order on January 20, 2025, which requires an immediate pause in the disbursement of funds appropriated through the IRA and IIJA during a 90-day review period, which is still in effect. Exelon is currently evaluating this EO and others to determine what, if any, impact they might have on awards selected or received from the Department of Energy in 2024. Next Generation Energy Act On April 7, 2025, the Maryland General Assembly, passed legislation that addresses several matters pertaining to electric and gas utilities, including affirming that the MDPSC may approve the use of multi-year rate plans that are proven to be beneficial to customers, among other things. It also prohibits utilities from filing after January 1, 2025, for the reconciliation of actuals costs and revenues to amounts approved within the multi-year plans. As of March 31, 2025, BGE has a regulatory asset of $10 million and a regulatory liability of $10 million for multi-year plan reconciliations yet to be filed. DPL has a regulatory liability of $7 million for multi-year reconciliations yet to be filed. Multi-year plan reconciliations filed prior to January 1, 2025, remain lawful and will be resolved in their respective proceedings. The legislation is pending the signature of the Governor. Exelon, BGE, Pepco, and DPL are in the process of assessing the potential impacts of the pending legislation. 92 Table of Contents 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, 2025, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2024. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2024 Form 10-K for further information. 93 Table of Contents Results of Operations by Registrant Results of Operations — ComEd Three Months Ended March 31, (Unfavorable) Favorable Variance 2025 2024 Operating revenues $ 2,065 $ 2,095 $ (30) Operating expenses Purchased power 689 907 218 Operating and maintenance 423 418 (5) Depreciation and amortization 380 362 (18) Taxes other than income taxes 99 94 (5) Total operating expenses 1,591 1,781 190 Operating income 474 314 160 Other income and (deductions) Interest expense, net (128) (122) (6) Other, net 21 20 1 Total other income and (deductions) (107) (102) (5) Income before income taxes 367 212 155 Income taxes 65 19 (46) Net income $ 302 $ 193 $ 109 Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024. Net income increased by $109 million as compared to the same period in 2024, primarily due to timing of distribution earnings, higher distribution and transmission rate base, and higher return on regulatory assets primarily due to an increase in asset balances. These were partially offset by lower transmission peak load. The changes in Operating revenues consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Distribution $ 129 Transmission 22 Energy efficiency 10 Other 9 170 Regulatory required programs (200) Total decrease $ (30) Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer, or number of customers as a result of revenue decoupling mechanisms. Distribution Revenue. Starting in 2024, distribution revenues are under a MRP. The MRP requires an annual reconciliation of the revenue requirement in effect to the actual costs the ICC determines are prudently and reasonably incurred. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenues increased for the three months ended March 31, 2025 as compared to the same period in 2024, primarily due to differences in the timing of distribution earnings and higher rate base. 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 94 Table of Contents ComEd for the three months ended March 31, 2025 as compared to the same period in 2024, primarily due to higher fully recoverable costs and the impacts of higher rate base, partially offset by lower transmission peak load. 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, 2025 as compared to the same periods in 2024, primarily due to increased regulatory asset amortization, which is fully recoverable. Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenues increased for the three months ended March 31, 2025 as compared to the same periods in 2024, which primarily reflects increased mutual assistance revenues associated with storm restoration efforts. Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. ETAC is a retail customer surcharge collected and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs. See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation. The $218 million decrease in Purchased power expense for the three months ended March 31, 2025 compared to the same periods in 2024 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, 2025 (Decrease) Increase Labor, other benefits, contracting, and materials $ (27) Storm-related costs (6) Pension and non-pension postretirement benefits expense 2 Other 40 9 Regulatory required programs (4) Total increase $ 5 95 Table of Contents ComEd The changes in Depreciation and amortization expense consisted of the following: Three Months Ended March 31, 2025 Increase Depreciation and amortization (a) $ 18 Total increase $ 18 __________ (a) Reflects ongoing capital expenditures. Effective income tax rat es we re 17.7% and 9.0% for the three months ended March 31, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 96 Table of Contents PECO Results of Operations — PECO Three Months Ended March 31, Favorable (Unfavorable) Variance 2025 2024 Operating revenues $ 1,333 $ 1,054 $ 279 Operating expenses Purchased power and fuel 502 403 (99) Operating and maintenance 327 293 (34) Depreciation and amortization 109 104 (5) Taxes other than income taxes 60 51 (9) Total operating expenses 998 851 (147) Gain on sales of assets — 2 (2) Operating income 335 205 130 Other income and (deductions) Interest expense, net (63) (55) (8) Other, net 8 9 (1) Total other income and (deductions) (55) (46) (9) Income before income taxes 280 159 121 Income taxes 14 10 (4) Net income $ 266 $ 149 $ 117 Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024. Net income increased by $117 million, due to an increase in revenue as a result of an increase in electric and gas distribution rates coupled with relatively normal weather compared to unfavorable weather in the same period last year and a decrease in income tax expense due to timing of tax repairs deduction, partially offset by an increase in credit loss expense and interest expense. The changes in Operating revenues consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Electric Gas Total Weather $ 23 $ 21 $ 44 Volume 9 2 11 Pricing 73 38 111 Transmission (6) — (6) Other 5 3 8 104 64 168 Regulatory required programs 71 40 111 Total increase $ 175 $ 104 $ 279 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, 2025 compared to the same period in 2024, Operating revenues related to weather increased due to relatively normal weather compared to unfavorable weather conditions in PECO's service territory. Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in 97 Table of Contents PECO PECO’s service territory for the three months ended March 31, 2025 compared to the same period in 2024 and normal weather consisted of the following: Three Months Ended March 31, % Change PECO Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal Heating Degree-Days 2,351 2,089 2,388 12.5 % (1.5) % Cooling Degree-Days 1 — 1 N/A — % Volume. Electric volume, exclusive of the effects of weather, for the three months ended March 31, 2025 compared to the same period in 2024, remained relatively consistent. Natural gas volume for the three months ended March 31, 2025 compared to the same period in 2024, remained relatively consistent. Electric Retail Deliveries to Customers (in GWhs) Three Months Ended March 31, % Change Weather - Normal % Change (b) 2025 2024 Residential 3,859 3,455 11.7 % 3.3 % Small commercial & industrial 1,946 1,891 2.9 % (1.0) % Large commercial & industrial 3,425 3,355 2.1 % (0.4) % Public authorities & electric railroads 189 179 5.6 % 5.6 % Total electric retail deliveries (a) 9,419 8,880 6.1 % 1.1 % At March 31, Number of Electric Customers 2025 2024 Residential 1,540,453 1,540,491 Small commercial & industrial 155,131 156,475 Large commercial & industrial 3,151 3,160 Public authorities & electric railroads 10,703 10,713 Total 1,709,438 1,710,839 __________ (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) 2025 2024 Residential 21,834 18,895 15.6 % (0.3) % Small commercial & industrial 10,405 9,488 9.7 % (2.2) % Large commercial & industrial 12 16 (25.0) % — % Transportation 7,242 6,899 5.0 % 1.0 % Total natural gas retail deliveries (a) 39,493 35,298 11.9 % (0.6) % At March 31, Number of Natural Gas Customers 2025 2024 Residential 509,773 508,429 Small commercial & industrial 44,869 45,038 Large commercial & industrial 7 7 Transportation 623 646 Total 555,272 554,120 __________ (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. 98 Table of Contents PECO (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, 2025 compared to the same period in 2024 increased primarily due to an increase in electric and gas distribution rates charged to customers. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue decreased for the three months ended March 31, 2025 compared to the same period in 2024 primarily due to decreases in underlying costs and capital investments. Other revenue primarily includes revenue related to late payment charges. Other revenue for the three months ended March 31, 2025 compared to the same period in 2024 remained relatively consistent. Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, TSC, and the GSA. The riders are designed to provide full and current cost recovery, and in some cases, a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs. See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation. The increase of $99 million for the three months ended March 31, 2025 compared to the same period in 2024, in Purchased power and fuel expense is offset in Operating revenues as part of regulatory required programs. 99 Table of Contents PECO The changes in Operating and maintenance expense consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Credit loss expense $ 17 Labor, other benefits, contracting and materials 9 BSC costs 1 Pension and non-pension postretirement benefit expense 1 Storm-related costs (4) Other (1) 23 Regulatory required programs 11 Total increase $ 34 The changes in Depreciation and amortization expense consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Depreciation and amortization (a) $ 7 Regulatory asset amortization (2) Total increase $ 5 __________ (a) Depreciation and amortization increased primarily due to ongoing capital expenditures. Taxes other than income taxes increased by $9 million for the three months ended March 31, 2025, compared to the same period in 2024, primarily due to higher Pennsylvania gross receipts tax. Interest expense, net increased $8 million for the three months ended March 31, 2025, compared to the same period in 2024, primarily due to an increase in interest rates and higher outstanding debt. Effective income tax rates were 5.0% and 6.3% for the three months ended March 31, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 100 Table of Contents BGE Results of Operations — BGE Three Months Ended March 31, Favorable (Unfavorable) Variance 2025 2024 Operating revenues $ 1,554 $ 1,297 $ 257 Operating expenses Purchased power and fuel 609 464 (145) Operating and maintenance 305 264 (41) Depreciation and amortization 164 150 (14) Taxes other than income taxes 96 89 (7) Total operating expenses 1,174 967 (207) Operating income 380 330 50 Other income and (deductions) Interest expense, net (58) (50) (8) Other, net 9 8 1 Total other income and (deductions) (49) (42) (7) Income before income taxes 331 288 43 Income taxes 71 24 (47) Net income $ 260 $ 264 $ (4) Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024. Net Income decreased $4 million primarily due to an increase in various operating expenses and an increase in interest expense, partially offset by favorable distribution rates. The changes in Operating revenues consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Electric Gas Total Distribution $ 33 $ 44 $ 77 Transmission 7 — 7 Other 2 (1) 1 42 43 85 Regulatory required programs 88 84 172 Total increase $ 130 $ 127 $ 257 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 2025 2024 Residential 1,220,769 1,213,063 Small commercial & industrial 115,359 115,406 Large commercial & industrial 13,302 13,110 Public authorities & electric railroads 258 261 Total 1,349,688 1,341,840 101 Table of Contents BGE At March 31, Number of Natural Gas Customers 2025 2024 Residential 661,195 658,818 Small commercial & industrial 37,945 37,982 Large commercial & industrial 6,380 6,336 Total 705,520 703,136 Distribution Revenue increased for the three months ended March 31, 2025, compared to the same period in 2024, due to favorable impacts of the multi-year plans. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2025, compared to the same period in 2024, primarily due to increases in underlying costs and capital investments. Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other Revenue remained relatively consistent for the three months ended March 31, 2025 compared to the same period in 2024. Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up. See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation. The increase of $145 million for the three months ended March 31, 2025 compared to the same period in 2024, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs. 102 Table of Contents BGE The changes in Operating and maintenance expense consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Labor, other benefits, contracting, and materials 12 BSC costs 3 Credit loss expense 2 Pension and non-pension postretirement benefits expense 1 Storm-related costs (5) Other 5 18 Regulatory required programs (a) 23 Total increase $ 41 __________ (a) Increase due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information. The changes in Depreciation and amortization expense consisted of the following: Three Months Ended March 31, 2025 Increase Depreciation and amortization $ 2 Regulatory required programs (a) 6 Regulatory asset amortization 6 Total increase $ 14 __________ (a) Increase due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information. Interest expense, net increased by $8 million for the three months ended March 31, 2025 compared to the same period in 2024, primarily due to the issuance of debt in the second quarter of 2024. Taxes other than income taxes increased by $7 million for the three months ended March 31, 2025 compared to the same period in 2024, primarily due to increased property taxes. Effective income tax rates were 21.5% and 8.3% for the three months ended March 31, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 103 Table of Contents PHI Results of Operations — PHI PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services, and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three months ended March 31, 2025 compared to the same period in 2024. See the Results of Operations for Pepco, DPL, and ACE for additional information. Three Months Ended March 31, Favorable (Unfavorable) Variance 2025 2024 PHI $ 194 $ 168 $ 26 Pepco 97 75 22 DPL 69 66 3 ACE 31 29 2 Other (a) (3) (2) (1) __________ (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, 2025 Compared to Three Months Ended March 31, 2024. Net Income increased by $26 million primarily due to favorable impacts from the Maryland and District of Columbia multi-year plans, higher DPL Delaware electric and gas DISC rates, higher transmission rates at Pepco and DPL, favorable weather conditions at DPL, partially offset by an increase in interest and depreciation expense at Pepco and DPL. 104 Table of Contents Pepco Results of Operations — Pepco Three Months Ended March 31, Favorable (Unfavorable) Variance 2025 2024 Operating revenues $ 859 $ 759 $ 100 Operating expenses Purchased power 318 281 (37) Operating and maintenance 159 150 (9) Depreciation and amortization 105 107 2 Taxes other than income taxes 113 102 (11) Total operating expenses 695 640 (55) Gain on sales of assets (1) — (1) Operating income 163 119 44 Other income and (deductions) Interest expense, net (52) (45) (7) Other, net 11 15 (4) Total other income and (deductions) (41) (30) (11) Income before income taxes 122 89 33 Income taxes 25 14 (11) Net income $ 97 $ 75 $ 22 Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024. Net Income increased by $22 million primarily due to favorable impacts from the Maryland and District of Columbia multi-year plans and higher transmission rates, partially offset by an increase in interest and depreciation expense. The changes in Operating revenues consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Distribution $ 45 Transmission 6 Other (3) 48 Regulatory required programs 52 Total increase $ 100 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 2025 2024 Residential 557,672 552,215 Small commercial & industrial 30,555 30,760 Large commercial & industrial 18,986 18,944 Public authorities & electric railroads 177 179 Total 607,390 602,098 105 Table of Contents Pepco Distribution Revenue increased for the three months ended March 31, 2025 compared to the same period in 2024 primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans and customer growth in Maryland. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2025, compared to the same period in 2024, primarily due to increases in underlying costs and capital investments. Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes. Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as Pepco remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore, Pepco does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. S ee Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation. The increase of $37 million for the three months ended March 31, 2025, compared to the same period in 2024, 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, 2025 (Decrease) Increase Labor, other benefits, contracting and materials $ (6) Credit loss expense (5) BSC and PHISCO costs (2) Other 5 (8) Regulatory required programs (a) 17 Total increase $ 9 _________ (a) Increase primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters for additional information. 106 Table of Contents Pepco The changes in Depreciation and amortization expense consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Depreciation and amortization (a) $ 7 Regulatory asset amortization 1 Regulatory required programs (b) (10) Total decrease $ (2) __________ (a) Depreciation and amortization increased primarily due to ongoing capital expenditures. (b) Decrease includes the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters additional information. Taxes other than income taxes increased $11 million for the three months ended March 31, 2025, compared to the same period in 2024, primarily due to increases in utility taxes, which are offset in revenues, and property taxes. Effective income tax rates were 20.5% and 15.7% for the three months ended March 31, 2025 and 2024. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 107 Table of Contents DPL Results of Operations — DPL Three Months Ended March 31, Favorable (Unfavorable) Variance 2025 2024 Operating revenues $ 548 $ 491 $ 57 Operating expenses Purchased power and fuel 247 215 (32) Operating and maintenance 106 95 (11) Depreciation and amortization 63 61 (2) Taxes other than income taxes 21 20 (1) Total operating expenses 437 391 (46) Operating income 111 100 11 Other income and (deductions) Interest expense, net (25) (22) (3) Other, net 4 5 (1) Total other income and (deductions) (21) (17) (4) Income before income taxes 90 83 7 Income taxes 21 17 (4) Net income $ 69 $ 66 $ 3 Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024. Net income increased $3 million primarily due to favorable weather conditions at Delaware electric and natural gas service territories, higher Delaware electric and gas DSIC rates, and higher transmission rates, partially offset by an increase in depreciation and interest expense. The changes in Operating revenues consisted of the following: Three Months Ended March 31, 2025 Increase Electric Gas Total Weather $ 4 $ 2 $ 6 Volume — 3 3 Distribution 5 1 6 Transmission 3 — 3 12 6 18 Regulatory required programs 30 9 39 Total increase $ 42 $ 15 $ 57 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, 2025 compared to the same period in 2024, Operating revenues related to weather increased due to favorable weather conditions in DPL's Delaware electric and natural gas service territories. 108 Table of Contents 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, 2025, compared to same period in 2024 and normal weather consisted of the following: Three Months Ended March 31, % Change Delaware Electric Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal Heating Degree-Days 2,399 2,204 2,420 8.8 % (0.9) % Cooling Degree-Days 9 — 1 — % 800.0 % Three Months Ended March 31, % Change Delaware Natural Gas Service Territory 2025 2024 Normal 2025 vs. 2024 2025 vs. Normal Heating Degree-Days 2,399 2,204 2,454 8.8 % (2.2) % Volume, exclusive of the effects of weather, increased for the three months ended March 31, 2025 compared to the same period in 2024, primarily due to an increase in customer usage and customer growth. Electric Retail Deliveries to Delaware Customers (in GWhs) Three Months Ended March 31, % Change Weather - Normal % Change (b) 2025 2024 Residential 930 857 8.5 % 1.9 % Small commercial & industrial 354 339 4.4 % 2.0 % Large commercial & industrial 690 718 (3.9) % (4.7) % Public authorities & electric railroads 7 7 — % 1.9 % Total electric retail deliveries (a) 1,981 1,921 3.1 % (0.5) % At March 31, Number of Total Electric Customers (Maryland and Delaware) 2025 2024 Residential 491,907 486,950 Small commercial & industrial 64,999 64,338 Large commercial & industrial 1,251 1,260 Public authorities & electric railroads 617 593 Total 558,774 553,141 __________ (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) 2025 2024 Residential 4,590 3,913 17.3 % 8.7 % Small commercial & industrial 1,970 1,717 14.7 % 5.1 % Large commercial & industrial 428 428 — % — % Transportation 2,106 1,960 7.4 % 2.9 % Total natural gas deliveries (a) 9,094 8,018 13.4 % 6.1 % 109 Table of Contents DPL At March 31, Number of Delaware Natural Gas Customers 2025 2024 Residential 131,716 130,427 Small commercial & industrial 10,254 10,182 Large commercial & industrial 15 16 Transportation 161 163 Total 142,146 140,788 __________ (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, 2025 compared to the same period in 2024 primarily due to higher electric and natural gas DSIC rates in Delaware that became effective January 2025. Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. During the three months ended March 31, 2025 compared to the same period in 2024, transmission revenue increased due to increases in underlying costs and capital investments. Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues. Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up. See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation. The increase of $32 million for the three months ended March 31, 2025, compared to the same period in 2024, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs. 110 Table of Contents DPL The changes in Operating and maintenance expense consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Credit loss expense $ 4 BSC and PHISCO costs 1 Storm-related costs (3) Labor and contracting (3) Other 1 — Regulatory required programs (a) 11 Total increase $ 11 __________ (a) Increase primarily due to the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. The changes in Depreciation and amortization expense consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Depreciation and amortization (a) $ 4 Regulatory asset amortization — Regulatory required programs (b) (2) Total increase $ 2 __________ (a) Depreciation and amortization increased primarily due to ongoing capital expenditures. (b) Decrease includes the cost recovery associated with EmPOWER Maryland. Please refer to 2024 10-K Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information Effective income tax rates were 23.3% and 20.5% for the three months ended March 31, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 111 Table of Contents ACE Results of Operations — ACE Three Months Ended March 31, Favorable (Unfavorable) Variance 2025 2024 Operating revenues $ 373 $ 358 $ 15 Operating expenses Purchased power 157 140 (17) Operating and maintenance 90 87 (3) Depreciation and amortization 64 74 10 Taxes other than income taxes 2 2 — Total operating expenses 313 303 (10) Operating income 60 55 5 Other income and (deductions) Interest expense, net (21) (20) (1) Other, net 3 5 (2) Total other income and (deductions) (18) (15) (3) Income before income taxes 42 40 2 Income taxes 11 11 — Net income $ 31 $ 29 $ 2 Three Months Ended March 31, 2025 Compared to Three Months Ended March 31, 2024 . Net income remained relatively consistent. The changes in Operating revenues consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Distribution $ 2 Transmission (2) — Regulatory required programs 15 Total increase $ 15 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 became effective, prospectively, in the third quarter of 2021. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. 112 Table of Contents ACE At March 31, Number of Electric Customers 2025 2024 Residential 508,354 505,793 Small commercial & industrial 62,861 62,704 Large commercial & industrial 2,824 2,893 Public authorities & electric railroads 723 728 Total 574,762 572,118 Distribution Revenue remained relatively consistent for the three months ended March 31, 2025 compared to the same period in 2024. Transmission Revenues Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue remained relatively consistent for the three months ended March 31, 2025 compared to the same period in 2024. Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes. Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs. See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation. The increase of $17 million for the three months ended March 31, 2025, respectively, compared to the same period in 2024 in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs. The changes in Operating and maintenance expense consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Storm-related costs $ 1 Credit Loss Expense 1 BSC and PHISCO costs (1) Labor and contracting (2) Other (3) (4) Regulatory required programs 7 Total increase $ 3 __________ 113 Table of Contents ACE The changes in Depreciation and amortization expense consisted of the following: Three Months Ended March 31, 2025 Increase (Decrease) Depreciation and amortization (a) $ 2 Regulatory asset amortization (3) Regulatory required programs (9) Total decrease $ (10) __________ (a) Depreciation and amortization increased primarily due to ongoing capital expenditures. Effective income tax rates were 26.2% and 27.5% for the three months ended March 31, 2025 and 2024, respectively. See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates. 114 Table of Contents Liquidity and Capital Resources (All Registrants) All results included throughout the liquidity and capital resources section are presented on a GAAP basis. The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $4.0 billion. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements. Cash Flows from Operating Activities The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period that began in June 2022, and all of its costs of doing so will be recovered through a rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset. See Note 3 — Regulatory Matters of the 2024 Form 10-K and Notes 2 — Regulatory Matters and 11 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation. 115 Table of Contents The following table provides a summary of the change in cash flows from operating activities for the three months ended March 31, 2025 and 2024 by Registrant: Increase (decrease) in cash flows from operating activities Exelon ComEd PECO BGE PHI Pepco DPL ACE Net income (loss) $ 250 $ 109 $ 117 $ (4) $ 26 $ 22 $ 3 $ 2 Adjustments to reconcile net income to cash: Non-cash operating activities 408 158 31 129 65 31 14 14 Collateral received, net 37 (3) 12 1 27 11 9 5 Income taxes 38 51 13 7 1 3 3 — Pension and non-pension postretirement benefit contributions (181) (184) (7) (9) 30 — — 4 Regulatory assets and liabilities, net (166) (239) 47 14 28 7 3 19 Changes in working capital and other assets and liabilities (178) (93) (60) (33) (64) (65) (27) 40 Increase (decrease) in cash flows from operating activities $ 208 $ (201) $ 153 $ 105 $ 113 $ 9 $ 5 $ 84 Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. Significant operating cash flow impacts for the Registrants for the three months ended March 31, 2025 and 2024 were as follows: • See Note 14 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities . • Changes in collateral depended upon whether the Registrant was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties remained relatively consistent comparing the three months ended March 31, 2025 to the three months ended March 31, 2024. See Note 8 — Derivative Financial Instruments for additional information. • See Note 6 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes . • Changes in Pension and non-pension postretirement benefit contributions relates to Exelon's increased contributions to the Qualified Plans during the three months ended March 31, 2025. See Note 14 — Retirement Benefits of the 2024 Form 10-K for additional information. • Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differing from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $84 million and $80 million for the three months ended March 31, 2025 and 2024, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $22 million, $6 million, $3 million, and $5 million for the three months ended March 31, 2025 and $28 million, $10 million, $4 million, and $8 million for the three months ended March 31, 2024, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the three months ended March 31, 2025 and 2024. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. 116 Table of Contents • Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $(238) million and $(178) 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, 2025, the established pricing resulted in both a receivable from, and payable to, nuclear-powered generating facilities. The change in receivable from nuclear-powered generating facilities, and the change in payable to nuclear-powered generating facilities, are reflected as a change in accounts receivable and a change in accounts payable and accrued expenses, respectively, within the cash flows from operations. Cash Flows from Investing Activities The following table provides a summary of the change in cash flows from investing activities for the three months ended March 31, 2025 and 2024 by Registrant: (Decrease) increase in cash flows from investing activities Exelon ComEd PECO BGE PHI Pepco DPL ACE Capital expenditures $ (179) $ 4 $ (63) $ (82) $ (60) $ (11) $ (22) $ (16) Proceeds from sales of assets (2) — — — — — — — Changes in intercompany money pool — — — — — 134 (12) — Other investing activities 6 — — (5) — — — — (Decrease) increase in cash flows from investing activities $ (175) $ 4 $ (63) $ (87) $ (60) $ 123 $ (34) $ (16) Significant investing cash flow impacts for the Registrants for three months ended March 31, 2025 and 2024 were as follows: • Changes in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants. • Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below. Cash Flows from Financing Activities The following table provides a summary of the change in cash flows from financing activities for the three months ended March 31, 2025 and 2024 by Registrant: Increase (decrease) in cash flows from financing activities Exelon ComEd PECO BGE PHI Pepco DPL ACE Changes in short-term borrowings, net $ (458) $ 183 $ (27) $ (8) $ (136) $ (68) $ (81) $ 13 Long-term debt, net 701 — — — (100) (75) (50) 25 Changes in intercompany money pool — — — — 3 — — (122) Issuance of common stock 173 — — — — — — — Dividends paid on common stock (22) (9) (37) (6) — (15) (1) 2 Distributions to member — — — — (14) — — — Contributions from parent/member — 48 (17) — (135) (94) (55) 13 Other financing activities 9 (1) — — 13 10 — — Increase (decrease) in cash flows from financing activities $ 403 $ 221 $ (81) $ (14) $ (369) $ (242) $ (187) $ (69) 117 Table of Contents Significant financing cash flow impacts for the Registrants for the three months ended March 31, 2025 and 2024 were as follows: • Changes in short-term borrowings, net , is driven by repayments on and issuances of notes due in less than 365 days. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants. • Long-term debt, net , varies due to debt issuances and redemptions each year. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the "Debt" section below for additional information. • Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool. • Issuance of common stock relates to issuances of Exelon common stock during the first quarter of 2025. See Note 12 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. • Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 18 — Commitments and Contingencies of the 2024 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared. Debt See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances. During the three months ended March 31, 2025, no long-term debt was retired and/or redeemed. Dividends Quarterly dividends declared by the Exelon Board of Directors during the three months ended March 31, 2025 and for the second quarter of 2025 were as follows: Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share (a) First Quarter 2025 February 12, 2025 February 24, 2025 March 14, 2025 $ 0.4000 Second Quarter 2025 April 29, 2025 May 12, 2025 June 13, 2025 $ 0.4000 __________ (a) Exelon's Board of Directors approved an updated dividend policy for 2025. The 2025 quarterly dividend will be $0.40 per share. Credit Matters and Cash Requirements The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $3.4 billion was available to support additional commercial paper as of March 31, 2025, and of which no financial institution has more than 6.2% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the three months ended March 31, 2025 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants 118 Table of Contents have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the 2024 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets. The Registrants believe their cash flows from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements. On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”), with certain sales agents and forward sellers and certain forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of Common stock under the Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the Equity Distribution Agreement. During the first quarter 2025, Exelon issued approximately 4.0 million shares of Common stock at an average gross price of $43.42 per share. The net proceeds from the issuance were $173 million, which were used for general corporate purposes. In the first quarter of 2025, Exelon entered into two separate forward sale agreements for 1.7 million shares and 4.0 million shares of Common stock, with an initial forward price of $42.81 and $43.42 per share, respectively. The forward sale agreements require Exelon to, at its election prior to December 15, 2025, either (i) physically settle the transactions by issuing shares of its Common stock to the forward counterparties in exchange for net proceeds at the then-applicable forward sale price specified by the agreements or (ii) net settle the transactions in whole or in part through the delivery to the forward counterparties or receipt from the forward counterparties of cash or shares in accordance with the provisions of the agreements. 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, 2025, approximately 5.6 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, $283 million of Common stock remained available for sale pursuant to the ATM program as of March 31, 2025. 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, 2025 and available credit facility capacity prior to any incremental collateral at March 31, 2025: PJM Credit Policy Collateral Other Incremental Collateral Required (a) Available Credit Facility Capacity Prior to Any Incremental Collateral ComEd $ 13 $ — $ 638 PECO — 45 596 BGE — 51 338 Pepco — — 298 DPL — 15 300 ACE — — 300 __________ (a) Represents incremental collateral related to natural gas procurement contracts. Capital Expenditure Spending As of March 31, 2025, the most recent estimates of capital expenditures for plant additions and improvements for 2025 are as follows: 119 Table of Contents (In millions) Transmission Distribution Gas Total (a) Exelon N/A N/A N/A $ 8,900 ComEd 950 2,250 N/A 3,200 PECO 200 1,300 375 1,875 BGE 700 625 525 1,850 PHI 650 1,400 100 2,150 Pepco 250 700 N/A 950 DPL 175 300 75 550 ACE 200 250 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 $275 million in 2025. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements. While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy. See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2024 Form 10-K for additional information on pension and OPEB contributions. Credit Facilities Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. See Note 9 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity. 120 Table of Contents Security Ratings The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets. The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements. As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 8 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions. The credit ratings for ComEd, BGE, PHI, Pepco, DPL, and ACE did not change for the three months ended March 31, 2025. On January 17, 2025, Fitch Ratings affirmed and withdrew the long-term and short-term issuer default ratings along with individual securities ratings of the Registrants for commercial reasons. On February 7, 2025, S&P raised its long-term issuer credit rating for Exelon and PECO from 'BBB+' to 'A-', and raised its rating on Exelon’s senior unsecured debt from ‘BBB’ to 'BBB+'. S&P also affirmed its short-term issuer and commercial paper rating for Exelon and PECO of 'A-2'. Intercompany Money Pool To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of March 31, 2025, are presented in the following table: During the Three Months Ended March 31, 2025 At March 31, 2025 Exelon Intercompany Money Pool Maximum Contributed Maximum Borrowed Contributed (Borrowed) Exelon Corporate $ 578 $ — $ 295 PECO — (253) — BSC — (378) (281) PHI Corporate — (85) (74) PCI 60 — 60 During the Three Months Ended March 31, 2025 At March 31, 2025 PHI Intercompany Money Pool Maximum Contributed Maximum Borrowed Contributed (Borrowed) Pepco $ 1 $ — $ — DPL 12 (1) 12 ACE — (12) (12) Shelf Registration Statements On February 21, 2024, PECO and BGE, as co-registrants, filed with the SEC a standalone automatically effective shelf registration statement, unlimited in amount, which can be used to issue PECO and BGE debt securities through the expiration date of February 20, 2027. On February 13, 2025, as most recently amended on March 27, 2025, Exelon Corporation and ComEd, as co-registrants filed a shelf registration statement with the SEC ("Exelon and ComEd Shelf Registration") for authorization of up to $12,575 million in additional security registration, to be used to issue Exelon Corporate debt securities and equity securities, as well as ComEd debt securities. The Exelon and ComEd Shelf Registration was declared effective by the SEC on April 8, 2025, and is 121 Table of Contents effective through April 8, 2028. The ability of Exelon Corporation, ComEd, PECO and BGE to sell securities off their corresponding registration Statements, or to access the private placement markets, will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions. Pepco, DPL and ACE periodically issue securities through the private placement markets. Pepco, DPL and ACE's ability to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, current financial condition, securities ratings and market conditions. Regulatory Authorizations The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows: At March 31, 2025 Short-term Financing Authority Remaining Long-term Financing Authority Commission Expiration Date Amount Commission Expiration Date Amount ComEd FERC December 31, 2025 $ 2,500 ICC January 1, 2027 & May 1, 2027 $ 2,318 PECO FERC December 31, 2025 1,500 PAPUC December 31, 2027 2,900 BGE (b) FERC December 31, 2025 700 MDPSC N/A 2,500 Pepco (a) FERC December 31, 2025 500 MDPSC / DCPSC December 31, 2025 175 DPL (a) FERC December 31, 2025 500 MDPSC / DEPSC December 31, 2025 250 ACE NJBPU December 31, 2025 350 NJBPU December 31, 2026 775 __________ (a) The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DCPSC and DEPSC have an expiration date of December 31, 2025. (b) On February 20, 2025, BGE received approval from the MDPSC for $2.2 billion in additional long-term financing authority. The additional financing authority has an effective date of February 20, 2025. 122 Table of Contents