exc-20250501ex992

May 1, 2025 Earnings Conference Call First Quarter 2025

2 Cautionary Statements Regarding Forward-Looking Information This presentation contains certain forward-looking statements within the meaning of federal securities laws that are subject to risks and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” “should,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements. Any reference to “E” after a year or time period indicates the information for that year or time period is an estimate. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that may cause our actual results or outcomes to differ materially from those contained in our forward-looking statements, including, but not limited to: unfavorable legislative and/or regulatory actions; uncertainty as to outcomes and timing of regulatory approval proceedings and/or negotiated settlements thereof; environmental liabilities and remediation costs; state and federal legislation requiring use of low-emission, renewable, and/or alternate fuel sources and/or mandating implementation of energy conservation programs requiring implementation of new technologies; challenges to tax positions taken, tax law changes, and difficulty in quantifying potential tax effects of business decisions; negative outcomes in legal proceedings; adverse impact of the activities associated with the past Deferred Prosecution Agreement and now-resolved U.S. Securities and Exchange Commission (SEC) investigation on Exelon’s and ComEd’s reputation and relationships with legislators, regulators, and customers; physical security and cybersecurity risks; extreme weather events, natural disasters, operational accidents such as wildfires or natural, gas explosions, war, acts and threats of terrorism, public health crises, epidemics, pandemics, or other significant events; disruptions or cost increases in the supply chain, including shortages in labor, materials or parts, or significant increases in relevant tariffs; lack of sufficient capacity to meet actual or forecasted demand or disruptions at power generation facilities owned by third parties; emerging technologies that could affect or transform the energy industry; instability in capital and credit markets; a downgrade of any Registrant’s credit ratings or other failure to satisfy the credit standards in the Registrants’ agreements or regulatory financial requirements; significant economic downturns or increases in customer rates; impacts of climate change and weather on energy usage and maintenance and capital costs; and impairment of long-lived assets, goodwill, and other assets. New factors emerge from time to time, and it is impossible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see those factors discussed with respect to Exelon Corporation, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants) in the Registrants’ most recent Annual Report on Form 10-K, including in Part I, ITEM A, any subsequent Quarterly Reports on Form 10-Q, and in other reports filed by the Registrants from time to time with the SEC. Investors are cautioned not to place undue reliance on these forward-looking statements, whether written or oral, which apply only as of the date of this presentation. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation.

3 Non-GAAP Financial Measures Exelon reports its financial results in accordance with accounting principles generally accepted in the United States (GAAP). Exelon supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures, including: • Adjusted operating earnings exclude certain items that are considered by management to be not directly related to the ongoing operations of the business as described in the Appendix. • Operating ROE is calculated using operating net income divided by average equity for the period. The operating income reflects all lines of business for the utility business (Gas Distribution, Electric Transmission, and Electric Distribution). • Adjusted cash from operations primarily includes cash flows from operating activities adjusted for common dividends and change in cash on hand. Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available without unreasonable efforts, as management is unable to project special items (such as effects of hedges, unrealized gains and losses, and legal settlements) for future periods. This information is intended to enhance an investor’s overall understanding of period over period financial results and provide an indication of Exelon’s baseline operating performance by excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. These non-GAAP financial measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations. Exelon has provided these non- GAAP financial measures as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. These non-GAAP measures should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP measures provided in the materials presented. Non-GAAP financial measures are identified by the phrase “non-GAAP” or an asterisk (*). Reconciliations of these non-GAAP measures to the most comparable GAAP measures are provided in the appendices and attachments to this presentation.

4 Key Messages Financial and Operational Excellence Regulatory & Other Developments Long-Term Outlook ▪ GAAP Earnings of $0.90 per share in Q1 2025 versus $0.66 per share in Q1 2024 ▪ Adjusted Operating Earnings* of $0.92 per share in Q1 2025 vs. $0.68 per share in Q1 2024 ▪ All utilities sustained top quartile or better performance in reliability and top decile in safety ▪ State legislative sessions all feature energy bills focused on energy security and affordability ▪ Maryland session concluded with laws supporting energy security, providing rules for large load customers, assisting customer affordability, and refining tools to support timely cost recovery ▪ Q4 pipeline of 17+ GW(1) of anticipated large load remains robust with line of sight to significant further growth, driving incremental investment opportunities beyond the plan ▪ Affirming 2025 EPS* of $2.64 - $2.74 per share(2) ▪ 7.4% rate base growth resulting from $38.0B of capital investment, and $10-15B of potential transmission opportunity beyond the plan ▪ $425M, or ~60%, of 2025’s annualized equity need of $700M priced for issuance this year, supporting balanced funding strategy for capital investment plan through 2028 ▪ Reaffirming 2024-2028 EPS* CAGR of 5-7%(3) with expectation to be at midpoint or better (1) Represents customer-driven requested capacity from projects in an official phase of engineering with deposits paid but not yet in-service as of Q4 2024; demand expected to ramp over a period of up to 10 years and may differ from initial estimates. 16 GW of additional load in Q1 2025 now undergoing analysis and design at request of customers. See Appendix slide 13 for additional detail. (2) 2025 earnings guidance based on expected average outstanding shares of 1,015M. (3) Based off the midpoint of Exelon’s 2024 Adjusted Operating EPS* guidance range of $2.40 - $2.50 as disclosed at Q4 2023 Earnings Call in February 2024.

Q1 2025 QTD Adjusted Operating Earnings* Waterfall $0.22 $0.17 $0.10 $0.11 $0.19 $0.15 $0.26$0.26 $0.26 ($0.11) ($0.11) Q1 2024 ComEd PECO $0.00 BGE $0.02 PHI $0.00 Corp Q1 2025 $0.68 $0.92 $0.32 $0.01 Distribution and Transmission Rates $0.09 Timing of Distribution Earnings $0.01 Return on Regulatory Assets ($0.01) Transmission Peak Load $0.08 Distribution Rates $0.03 Weather $0.02 Income Taxes (1) ($0.01) Interest Expense ($0.01) Other 5 BGE PECO PHI ComEd Corp $0.02 Distribution Rates ($0.01) Interest Expense ($0.01) Other $0.03 Distribution and Transmission Rates ($0.01) Interest Expense Note: Amounts may not sum due to rounding (1) Lower income taxes driven primarily by timing of tax repairs deduction.

6 Distribution Rate Case and Other Regulatory Updates Rate case filed Rebuttal testimony Initial briefs Final commission order Intervenor direct testimony Evidentiary hearings Reply briefs Settlement agreement CF IT RT EH IB RB FO SA Note: See slide 20 for further detail on pertinent rate case data and information. DPL DE Gas Filed base distribution rate cases for 2025 account for ~5% of Exelon’s consolidated rate base ACE Electric Mar Apr May Jun Jul Aug Sept Oct Nov Dec Jan Feb Mar Revenue Requirement Increase Requested ROE / Equity Ratio Expected Order Date $41.6M 10.65% / 50.50% Q1 2026 $108.9M 10.70% / 50.24% Dec 2025 IT RT EH IT RT EH FO FO Open Base Rate Cases Other Regulatory Activity • BGE Reconciliation (Case No. 9645) – $152M request for under recovered costs in 2023 – Reply briefs filed on 3/7/2025 – Awaiting PSC final order • Maryland Lessons Learned (Case No. 9618) – Briefs filed on 12/13/2024 – Awaiting PSC next steps • Pepco MD Reconciliation (Case No. 9655) – $31M request for under recovered costs in Rate Year 3 (12-months ending 3/31/24) – Reply briefs filed 4/22/2025 – Awaiting PSC final order • ComEd Reconciliation (Case No. 25-0383) – MRPP Annual Performance Evaluation proceeding – $268M adjustment, including the 2024 Performance Adjustment – Testimony and supporting exhibits filed 4/29/2025 – Staff and Intervenor Direct Testimony in July 2025

▪ Continued financial flexibility over our downgrade thresholds, managing risks while funding growth in a balanced, ratable fashion – Exelon’s scale, jurisdictional diversification, operational excellence, and effective recovery mechanisms contribute to a unique credit-supportive value proposition ▪ Executed ~50% of 2025 debt financing needs in Q1, including all expected at HoldCo, substantially mitigating remaining exposure to interest rate volatility for this year – Corporate debt financing included $1.0B of hybrid debt, which receives 50% equity credit ▪ Pre-issuance hedging strategy further reduces future interest rate volatility ▪ $38B four-year capital expenditure plan being funded in a balanced manner – Financing plan implies $700M of equity to be issued annually through 2028 – Priced ~60% of annualized equity needs in Q1 through ATM Strong Balance Sheet Provides Strategic and Financial Flexibility Credit Metric Outlook %*(2,3) Credit Ratings / Outlooks(5) ExCorp ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 (Stable) A1 (Stable) Aa3 (Negative) A3 (Stable) A2 (Stable) A2 (Positive)(6) A2 (Stable) S&P BBB+ (Stable) A (Stable) A (Stable) A (Negative) A (Stable) A (Stable) A (Stable) (1) Represents Exelon’s average credit metrics since separation of ~13%; Exelon’s 2022, 2023, and 2024 actuals per S&P and Moody’s published data. (2) 2025–2028 average internal credit metric estimates based on S&P and Moody’s methodology. Chart provides an illustrative view of Exelon’s anticipated trajectory by 2028 and does not reflect year-over-year shaping influenced by one-time items, cash flow timing factors with high certainty of future recovery, among other considerations. (3) With the tax repairs deduction, Corporate Alternative Minimum Tax (CAMT) would be fully mitigated, resulting in a ~0.5% increase to the 2025 – 2028 average credit metric. (4) Represents Moody’s downgrade threshold for Exelon Corporate’s Baa2 senior unsecured rating. S&P’s downgrade threshold is 13% for Exelon Corporate’s BBB+ senior unsecured rating (currently one notch higher than Moody’s). (5) Current senior unsecured ratings for Exelon and BGE and current senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco. (6) On April 21, 2025, Moody’s revised the outlook on DPL from stable to positive. 12% 13% 14% 2022 – 2024 Average(1) 2025 2026 2027 2028 Meaningful financial flexibility over downgrade thresholds will strengthen over planning horizon, with further upside from targeted operating levers Downgrade Threshold(4) 7

8 2025 Business Priorities and Commitments Focused on continued execution of operational, regulatory, and financial priorities to advance the interest of our customers and build on the strength of Exelon’s value proposition as the premier T&D energy company ❖ Foster a culture of excellence by prioritizing employee safety and engagement ❖ Deploy $9.1B of capex for the benefit of our customers ❖Maintain industry-leading operational excellence ❖ Focus on customer affordability, including through cost management and innovation ❖ Advocate for equitable and balanced energy transition ❖ Partner with our jurisdictions to capture growth opportunities and new customer solutions, including ensuring energy security needs are met in an equitable manner ❖ Earn consolidated operating ROE* of 9-10% ❖ Achieve constructive rate case outcomes for customers and shareholders ❖ Deliver against operating EPS* guidance of $2.64 - $2.74 per share(1) ❖Maintain strong balance sheet and execute on 2025 financing plan (1) 2025 adjusted operating earnings guidance based on expected average outstanding shares of 1,015M.

Customer rates 21% below largest U.S. cities(1) Award-winning, innovative solutions for customer choice and affordability, recognized as ENERGY STAR® Partner of the Year Top-tier customer service for site selection across Exelon’s footprint C u s to m e r- F o c u s e d Proven track record, committed to delivering on financial commitments 7.4% rate base growth with established rate mechanisms in place Strong investment grade credit ratings with plan approaching 200 bps of financial flexibility Diverse and defined capital plan with no one project greater than ~3% of 4-year outlook 9 Sustainable Value as the Premier T&D Energy Company (1) Source: Edison Electric Institute Typical Bills and Average Rates report for Summer 2024; reflects residential average rates for the 12-month period ending June 30, 2024. (2) Preliminary estimate of 2024 supplier spend data, subject to final supplier spend data to be published in Exelon's 2025 Sustainability Report. (3) Based off the midpoint of Exelon’s 2024 Adjusted Operating EPS* guidance range of $2.40 - $2.50 as disclosed at Q4 2023 Earnings Call in February 2024. (4) Aggregate amount of dividends to be paid quarterly and are subject to approval by Board of Directors. Investing in infrastructure for our communities generates 5-7% annualized operating earnings growth(3), which combined with ~60% dividend payout ratio(4) results in an attractive risk-adjusted total annual return of 9-11% Top quartile reliability, ComEd #1 Outstanding Performance in the Midwest by ReliabilityOne Cost and executional advantage due to size and scale with WSJ recognition as a Best Managed Company ~54% of Exelon’s total supplier spend is spent with local businesses and ~37% spent with diverse suppliers(2) 100+ workforce development programs #3 World’s Most Admired Power Company by Fortune Industry leader in advancing safety #1 in Energy on Fast Company’s Best Workplaces for Innovators 2024 F in a n c ia l E x e c u ti o n O p e ra ti o n a l E x c e ll e n c e T a le n te d , C o m m it te d E m p lo y e e s Consistent Growth, Long-Term Value

10 Additional Disclosures

Optimally Positioned for Growing Transmission Needs 11 Existing Infrastructure ▪ Reliability & Resiliency ▪ Congestion Relief ▪ Generator Deactivation ▪ Aging & System Hardening ▪ Operational Flexibility & Efficiency New Business ▪ $1B+ associated with high-density load in our pipeline not yet in guidance RTO-Adjacent Opportunities ▪ $1B+ potential for MISO LRTP Tranche 2.1 ▪ Other RTO Seam Interconnections ▪ Interregional transfer capabilities New Generation ▪ State Driven Public Policy Goals ▪ Other New Generation Interconnections Transmission investment needs continue to grow . . . ▪ Increased reliability and resiliency amidst more volatile weather patterns ▪ Accelerating load growth fueled by high-density customers ▪ Evolving and expanding generation supply stack of identified transmission opportunity beyond the plan, reinforcing Exelon’s enduring role in ensuring a resilient grid for the nation’s economy(1)$10-15B . . . while Exelon’s network is positioned to meet those needs ▪ Over 11,000 circuit miles of transmission lines ▪ Serve 4 major cities, including a top 5 data center market ▪ States with ambitious energy transition and development goals (1) As of Q4 2024 earnings call. Transmission opportunity largely expected in 2029 and beyond, though some categories such as new business may require additional spend before 2029.

12 Focus on reliability, affordability, and speed to market has positioned our jurisdictions to compete well for the growing economic development opportunities that rely on the grid Exelon is a Key Partner in Driving Economic Development 0 100 200 300 400 500 600 ‘15 ‘16 ‘17 ‘18 ‘19 ‘20 ‘21 ‘22 ‘23 ‘24 ~9% CAGR ~24% CAGR Historical Data Center Load in Northern IL(1) M W Projected Data Center Load Growth in Exelon’s Footprint(2) G W (1) Represents historical on-peak hourly demand for in-service data centers in the ComEd service territory. (2) Phases 1-3 represent customer-driven requested capacity from projects in an official phase of engineering with deposits paid but not yet in-service as of Q4 2024. Phase 1 represents projects where initial design is complete and deposits are collected; phase 2 projects have completed more definitive engineering and cost estimates, conducting PJM study; phase 3 projects are in construction. Demand expected to ramp over a period of up to 10 years and may differ from initial estimates. (3) Includes 12 GW of Phase 1 load being studied as a part of a batch process (“cluster study”) along with 4 GW of other additions that entered phase 1 in 2025. Inclusion in phase 1 pipeline pending finalization of ongoing or potential cluster studies. Publicly Announced Data Center Projects A proven leader in the data center market... …with a pipeline for continued growth ~200 online data centers served in our service territories with Illinois leading the way as a top 5 data center market in the U.S. High-quality service and a leader in reliability at competitive rates ComEd and PECO regularly recognized as top 20 utilities in economic development in the U.S. by Site Selection Magazine Pepco named the 2024 DC Chamber of Commerce Business of the Year 1 6 11 16 0 Q4 ’22 Q4 ’23 Q3 ’24 Q4 ’24 Q1 ’25 2025 Additions(3) Phase 3 Phase 2 Phase 1 16+

Energy Security and Associated Policy is a Top Priority Delivering resources to meet energy and economic goals requires all stakeholders working together to advance resilient, durable, and cost-effective solutions, and Exelon is engaged at all levels to sustain progress 13 StatesFederal Agencies Regional Transmission Operator (1) Date passed into legislation or anticipated conclusion of legislative session (2) Awaiting Governor Moore’s signature; see slide 12 for additional detail (3) PA Power Act – HB 1272 Oversee and guide RTOs, enhance markets, and support transmission development ▪ FERC 206 Proceeding on Co-Location ▪ PJM, PJM Transmission Owners, and a number of other industry stakeholders filed timely responses indicating that large co- located loads be in front of the meter and designated as PJM Network Load ▪ Industry and FERC continue to demonstrate urgency in reaching resolution ▪ Resource Adequacy Technical Conference – June 4-5, 2025 ▪ Covers Resource Adequacy challenges across RTOs/ISOs ▪ Day 1 will almost exclusively focus on PJM Develop and implement structures that promote cost-effective procurement and transmission of adequate energy supplies ▪ Capacity Market Price Collar Settlement (PA) setting cap and floor for 26/27 and 27/28 capacity auctions (FERC accepted 4/21/25) ▪ Reliability Resource Initiative (RRI) attracted 26.6 GW new or increased capacity ▪ Expedited Surplus Interconnection Service Process (FERC accepted 2/12/25) ▪ Capacity Market Reforms (FERC accepted 2/14/25) ▪ RMR treatment through 2028 ▪ Reference resource updates ▪ Extend must-offer requirements ▪ Market Seller Offer rules ▪ Capacity Interconnection Rights Transfer Reforms (pending) Adopt policy that promotes energy security, economic development, and reliable and resilient energy delivery ▪ MD (4/7/25)(1): Passed three bills(2) focused on energy security, battery storage investment opportunities, rules for large load customer connections, & clarifying use of MYPs ▪ IL (5/31/25)(1): Proposed bills address transmission, battery storage, energy efficiency, large load / data centers (including interconnection) ▪ PA (12/31/26)(1): Draft bill(3) advances energy security, allowing for regulated generation in conjunction with procurement via long-term contracts ▪ NJ (1/13/26)(1): Proposed bills address energy security, affordability, & clean energy commitments ▪ DE (6/30/25)(1): Proposed bills address customer affordability; energy security task forces to include battery storage

Maryland Legislation in Focus: Next Generation Act (SB 937), Energy Resource Adequacy and Planning Act (SB 909), Renewable Energy Certainty Act (SB 931) Forward-Looking Ratemaking Recognizes MYPs in law and authorizes PSC to approve those that demonstrate customer benefits Prohibits public service companies from filing reconciliations after January 1, 2025 for MYPs Securing Maryland’s Energy Future Establishes Strategic Energy Planning Office (SEPO) within PSC PSC solicitation, initiated by October 2025, of 3 GW of dispatchable generation, with shortened CPCN process, to include nuclear, gas, offshore wind, and battery storage Allows for 150 MW distribution-connected storage (target 70% owned by investor-owned electric utilities) Procurement of 1.6 GW transmission- connected storage (including utility-owned) PSC charged with studying PPAs, utility- owned generation, and other procurement models for in-state generation Prioritizing Customer Affordability Requires that electric companies file a distribution tariff for large load customers, focusing on appropriate cost allocations Creates a Legislative Energy Relief Fund, awarding grants to electric companies to fund two customer credits in the next fiscal year 14 Note: Bill descriptions are only summaries and subject in all respects to the complete text of each bill.

Financing ▪ $2.8B equity need (implies $700M annual), $3B of new Corporate debt 2025-2028, and other financing costs Operating Earnings* Growth Outlook 2025 2026 2027 2028 Total YoY Growth Relative to Range Growth Above 5-7% Range(1) Growth at Low End of 5-7% Range(2) Growth Above Midpoint of 5-7% Range Growth Below Midpoint of 5-7% Range (1) Based off the midpoint of Exelon’s 2024 Adjusted Operating EPS* guidance range of $2.40 - $2.50 as disclosed at Q4 2023 Earnings Call in February 2024. (2) Based off the midpoint of Exelon’s 2025 Adjusted Operating EPS* guidance range of $2.64 - $2.74 as disclosed at Q4 2024 Earnings Call in February 2025. (3) Growth outlook and associated drivers as of Q4 2024 earnings call. (4) Brandon Shores and Tri-County Line projects assumed to primarily earn AFUDC through the 2025-2028 guidance period. Rate case activity and investment plan drives path for 5-7% annualized adjusted operating earnings* growth, with close to 90% of Exelon’s rate base covered by established recovery mechanisms through 2026-2027 15 Growth Drivers 2025-2028(3) Distribution Transmission ▪ Growth in line with rate base ▪ Capital reflects 4-year MYP though 2027, including current estimates of new business connections to be recovered via reconciliation ▪ Annual transmission updates occurring mid-year, with generally longer construction periods versus distribution ▪ New electric and gas rates in effect 1/1/2025 ▪ Subsequent rate filings every 2-3 years; assumes weather normal revenue and Distribution System Improvement Charge (DSIC) ▪ Annual transmission updates occurring mid-year, with generally longer construction periods versus distribution ▪ Includes investment associated with Brandon Shores and Tri-County Line projects, which are expected to be fully placed in-service by 2028 and 2030, respectively(4) ▪ 3-year electric and gas MYP through 2026, and 2027+ investment plan and associated cost recovery will accommodate recommendations from MD Lessons Learned process ▪ Pepco MD MYP through March 2025 and DPL MD MYP through December 2025, and investment plans and associated cost recovery will accommodate recommendations from MD Lessons Learned process ▪ DC MYP2 through 2026 and continued recovery of spend in 2027-2028 via alternative ratemaking mechanisms ▪ Intermittent historical test-year rate cases at ACE and DPL, complemented by capital (ACE, DPL DE) and energy efficiency (ACE) trackers.

2025 Financing Plan(1) Capital plan financed with a balanced approach to maintain strong investment grade ratings Entity Instrument Issuance ($M) Maturity ($M) Issued ($M)(2) Remaining ($M) FMB $725 - - $725 FMB $275 - $275 - FMB $250 ($150) $250 - FMB / Tax-Exempts $203 ($78) $125 $78 FMB $1,050 ($350) - $1,050 Senior Notes $650 - - $650 Senior Notes / Other(3) $2,000 ($807) $2,000(3) - Equity(4) $700 - $425(4) $275 16 Note: As of March 31, 2025. FMB represents First Mortgage Bonds. (1) Financing plans are subject to change, depending on capital expenditures, regulatory outcomes, internal cash generation, market conditions, changes in tax policies, and other factors. (2) ACE, DPL, and Pepco priced FMBs in the private placement market on February 27, 2025. On March 26, 2025, ACE, DPL, and Pepco funded $100M, $125M, and $200M, respectively. Using a delayed draw feature, Pepco and ACE will fund $75M and $150M in September 2025 and November 2025, respectively. (3) Other could include fixed income securities that receive equity credit, subject to market conditions. Of the $2B, $1B was issued in hybrid debt and $1B in Senior Notes. (4) Exelon expects to issue ~$2.8B of equity by 2028, implying ~$700M per year. $250M of the $425M was issued under a forward agreement to be settled by December 15, 2025.

Exelon Debt Maturity Profile(1,2) Debt Balances (as of 3/31/25)(1,2) ($B) Short-Term Debt Long-Term Debt Total Debt BGE $0.2 $5.4 $5.6 ComEd $0.3 $12.2 $12.6 PECO $0.0 $5.9 $5.9 PHI $0.0 $9.5 $9.5 Corp $0.5(3) $14.1 $14.6 Exelon $1.1 $47.2 $48.3 807 750 650 1,000 650 1,250 500 1,016 850 650 833 1,430 675 815 200 600 1,400 650 741 691 1,275 2,150 1,550 673 2,150 669 1,050 1,825 1,500 578 850 360 997 303 600 1,100 625 2,323 1,645 400 1,225 1,200 1,650 2,400 1,650 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 100 20392025 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 2054 20552040 (1) Maturity profile excludes non-recourse debt, capital leases, fair value adjustments, unamortized debt issuance costs and unamortized discount/premium. (2) Long-term debt balances reflect 2025 Q1 10-Q GAAP financials, which include items listed in footnote 1. (3) Includes $500M of 364-day term loan maturing March 2026. Exelon’s weighted average long-term debt maturity is approximately 16 years ($M) As of 3/31/2025 EXC Regulated ExCorp 17

18 Exelon Adjusted Operating Earnings* Sensitivities Interest Rate Sensitivity to +50bp 2025E 2026E Cost of Debt (1) $(0.00) $(0.01) Exelon Consolidated Effective Tax Rate 16.8% 20.1% Exelon Consolidated Cash Tax Rate(2) 8.8% 13.4% (1) Reflects full year impact to a +50bp increase on Corporate debt net of pre-issuance hedges as of March 31, 2025. Through March 31, 2025, Corporate entered into $0.6B of pre-issuance hedges through interest rate swaps. (2) Includes the impact of CAMT.

19 Rate Case Details

20 Exelon Distribution Rate Case Updates Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Revenue Requirement Increase Approved/Requested ROE / Equity Ratio Expected/Received Order Date $41.6M(1,2) 10.65% / 50.50% Q1 2026 $108.9M(1,3,4) 10.70% / 50.24% Dec 2025 Rate case filed Rebuttal testimony Initial briefs Final commission order Intervenor direct testimony Evidentiary hearings Reply briefs Settlement agreement CF IT RT EH IB RB FO SA Note: Unless otherwise noted, based on schedules of Delaware Public Service Commission (DE PSC) and New Jersey Board of Public Utilities (NJ BPU) that are subject to change. (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings. (2) Requested revenue requirement excludes the transfer of $6.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, DPL implemented interim rates effective 4/20, subject to refund. (3) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings. Excludes the requested transfer of $11.1 million of Infrastructure Investment Program costs (IIP) and $8M of Sales and Use Tax into distribution rates. (4) As allowed by regulations, ACE plans to implement interim rates in effect on August 21, 2025, subject to refund. DPL DE Gas ACE Electric IT RT EH IT RT EH FO FO

21 DPL DE (Gas) Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 24-1044 ▪ September 20, 2024, Delmarva Power filed an application with the Delaware Public Service Commission (DE PSC) seeking an increase in gas distribution base rates ▪ Request driven by continued investments in gas distribution system to maintain reliability, customer service, and safety. The filing includes major projects such as: ▪ Pipeline Integrity Management: Inspects and maintains gas mains and valves, ensuring reliable energy and faster leak detection. ▪ Cast Iron Replacement: Upgrading old pipes with safer, more reliable polyethylene, finishing five years ahead of schedule. ▪ LNG Plant Upgrade: Enables efficient refilling during winter, ensuring a stable gas supply during peak demand which allows for improved bill predictability for customers. ▪ DPL is proposing a gas weather normalization adjustment, effective from October to May designed to adjust for differences between normalized, historical and actual weather ▪ The adjustment will provide customers with more bill predictability, while allowing DPL the opportunity to earn its authorized distribution revenues Test Period 9 months estimated + 3 months actual Test Year April 1, 2024 – March 31, 2025 Proposed Common Equity Ratio 50.50% Proposed Rate of Return ROE: 10.65%: ROR: 7.55% Proposed Rate Base (Adjusted) $609M Requested Revenue Requirement Increase $41.6M(1) Residential Total Bill % Increase 18.6% Detailed Rate Case Schedule Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar 9/20/2024 7/25/2025Intervenor testimony 9/5/2025Rebuttal testimony Filed rate case 11/12/2025 - 11/13/2025Evidentiary hearings Reply briefs Commission order expected(2) Q1 2026 Initial briefs (1) Requested revenue requirement excludes the transfer of $6.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, DPL implemented interim rates effective 4/20, subject to refund. Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings. (2) There is no statutory deadline by which the Commission needs to rule.

22 ACE Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. ER24110854 ▪ November 21, 2024, Atlantic City Electric filed with the New Jersey Board of Public Utilities (NJ BPU) to adjust base rates ▪ Rate increases allow for system upgrades and energy grid enhancements to improve performance through major infrastructure projects and grid modernization work, making the energy grid more resilient against storms to further improve reliability for our customers. The filing seeks recovery for: ▪ Smart Energy Network (SEN) investments that supports New Jersey’s energy master plan and the Clean Energy Act ▪ Incremental costs related to the recent work stoppage that would be amortized over 5 years ▪ Deferred accounting treatment for costs related to wildfires and wildfire mitigation Test Period 12 months actual Test Year September 2024 Proposed Common Equity Ratio 50.24% Proposed Rate of Return ROE: 10.70%: ROR: 7.36% Proposed Rate Base (Adjusted) $2,472M Requested Revenue Requirement Increase $108.9M(1,2) Residential Total Bill % Increase 8.1% Detailed Rate Case Schedule Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 8/11/2025 - 8/12/2025 Filed rate case Evidentiary hearings 11/21/2024 Rebuttal testimony Reply briefs Dec 2025 5/9/2025 Initial briefs 7/29/2025 - 7/31/2025 6/19/2025 8/5/2025 - 8/7/2025 Intervenor testimony Commission order expected(3) (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings. Excludes the requested transfer of $11.1 million of Infrastructure Investment Program costs (IIP) and $8M of Sales and Use Tax into distribution rates. (2) As allowed by regulations, ACE plans to implement interim rates in effect on August 21, 2025, subject to refund. (3) There is no statutory deadline by which the Board of Public Utilities needs to rule.

23 Approved Electric Distribution Rate Case Financials Approved Electric Distribution Rate Case Financials Revenue Requirement Increase/(Decrease) Allowed ROE Common Equity Ratio Rate Effective Date ComEd (Electric) (1,2) $1,045.0M 8.905% 50.0% Jan 1, 2024 PECO (Electric) (3) $290.0M N/A N/A Jan 1, 2025 BGE (Electric) (4,5) $179.1M 9.50% 52.00% Jan 1, 2024 Pepco MD (Electric) (6) $44.6M 9.50% 50.50% Apr 1, 2024 Pepco D.C. (Electric) (7) $123.4M 9.50% 50.50% Jan 1, 2025 DPL MD (Electric) (8) $28.9M 9.60% 50.50% Jan 1, 2023 DPL DE (Electric) (9) $27.8M 9.60% 50.50% April 24, 2024 ACE (Electric) (10) $45.0M 9.60% 50.20% Dec 1, 2023 (1) Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. The MRP was originally approved by the ICC on December 14, 2023, and was subsequently amended on January 10, 2024, April 18, 2024, and December 19, 2024. The December 19, 2024, order provided a total revenue requirement increase of $1.045B, inclusive of rate increases of approximately $752M in 2024, $80M in 2025, $102M in 2026, and $111M in 2027. ComEd originally requested a $1.487B increase from 2024-2027. On January 10, 2024, ComEd filed an appeal with the Illinois Appellate Court of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905% ROE, 50% equity ratio, and denial of any return on ComEd’s pension asset. (2) On April 10, 2025, the ICC initiated its annual performance evaluation proceeding, ICC Docket No. 25-083, to reconcile 2024 costs and determine ComEd’s performance on its metrics targets. ComEd is requesting recovery of approximately $268M in 2024 costs; the approved reconciliation balance will be collected in customer bills beginning in January 2026. (3) The PA PUC issued an order on December 12, 2024 approving the Joint Petition for Settlement with rates effective on January 1, 2025. Base rate revenue increase of $354M, which is partially offset by a one-time credit of $64M in 2025, resulting in a net revenue increase of $290M in 2025. The one-time credit of $64M includes ~$48M for incremental COVID-19 related uncollectible expense and ~$16M for dark fiber revenues. The settlement does not stipulate any ROE, Equity Ratio, or Rate Base. (4) Reflects a 3-year cumulative multi-year plan for 2024-2026. The MDPSC awarded incremental revenue requirement increases of $167M, $175M, and $66M with in each rate effective year, respectively. The incremental revenue requirement increase in 2024 reflects $41M increase for electric and $126M increase for gas; 2025 reflects $113M increase for electric and $62M increase for gas; 2026 reflects $25M increase for electric and $41M increase for gas. These include an acceleration of certain tax benefits in 2024 for both electric and gas. (5) On April 24, 2024, BGE filed with the MDPSC under case number 9645 its request for recovery of the 2023 reconciliation amounts of $79M and $73M for electric and gas, respectively. Of those amounts, $14M and $33M relate to under- recovered costs at electric and gas, respectively, for which associated revenues can only be recognized upon being billed to customers. (6) On July 29, 2024, Pepco MD filed with the MDPSC under case number 9655 its request for recovery of the Rate Year 3 reconciliation amount of $31M. Of that amount, $7M relates to under-recovered costs for which associated revenues can only be recognized upon being billed to customers. (7) Reflects a cumulative multi-year plan from 2025 to 2026. The DC PSC approved $123.4M of incremental revenue requirement increase with $99.7M and $23.7M of that increase going into effect with rates on January 1, 2025 and January 1, 2026, respectively. (8) Reflects 3-year cumulative multi-year plan. On October 7, 2022, DPL filed a partial settlement with the MDPSC, which included incremental revenue requirement increases of $16.9M, $6.0M and $6.0M with rates effective January 1, 2023, January 1, 2024, and January 1, 2025, respectively. The MDPSC approved the settlement without modification on December 14, 2022. (9) Revenue requirement excludes the transfer of $14.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. Delmarva Power implemented fully proposed rates on July 15, 2023 and adjusted them to final approved rates on April 24, 2024. (10) On November 17, 2023, the NJBPU approved the Company’s Settlement that reflects an overall increase of $45M to base distribution rates which is occurring in two phases. Phase I rates reflecting a $36M increase to base distribution rates became effective as of December 1, 2023. Phase II rates reflecting a $9M increase to base distribution rates became effective as of February 1, 2024.

24 Approved Gas Distribution Rate Case Financials Approved Gas Distribution Rate Case Financials Revenue Requirement Increase/(Decrease) Allowed ROE Common Equity Ratio Rate Effective Date PECO (Gas) (1) $78.0M N/A N/A Jan 1, 2025 BGE (Gas) (2,3) $228.8M 9.45% 52.00% Jan 1, 2024 DPL DE (Gas) (4) $7.6M 9.60% 49.94% Nov 1, 2022 (1) The PA PUC issued an order on December 12, 2024 approving the Joint Petition for Settlement with rates effective on January 1, 2025. The settlement does not stipulate any ROE, Equity Ratio, or Rate Base. (2) Reflects a three-year cumulative multi-year plan for 2024-2026. The MDPSC awarded incremental revenue requirement increases of $167M, $175M, and $66M with in each rate effective year, respectively. The incremental revenue requirement increase in 2024 reflects $41M increase for electric and $126M increase for gas; 2025 reflects $113M increase for electric and $62M increase for gas; 2026 reflects $25M increase for electric and $41M increase for gas. These include an acceleration of certain tax benefits in 2024 for both electric and gas. (3) Separately, on April 24, 2024, BGE filed with the MDPSC under case number 9692 its request for recovery of the 2023 reconciliation amounts of $79M and $73M for electric and gas, respectively. Of those amounts, $14M and $33M relate to under-recovered costs at electric and gas, respectively, for which associated revenues can only be recognized upon being billed to customers. (4) Revenue requirement excludes the transfer of $5.8M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. DPL implemented full proposed rates on August 14, 2022 and adjusted them to final approved rates on November 1, 2022.

25 Approved Electric Transmission Formula Rate Financials Approved Electric Transmission Formula Rate Financials Revenue Requirement Increase/(Decrease) Allowed ROE(1) Common Equity Ratio Rate Effective Date(2) ComEd $20M 11.50% 54.82% Jun 1, 2024 PECO $3M 10.35% 53.56% Jun 1, 2024 BGE $53M 10.50% 53.80% Jun 1, 2024 Pepco $73M 10.50% 50.28% Jun 1, 2024 DPL $24M 10.50% 50.52% Jun 1, 2024 ACE $33M 10.50% 50.20% Jun 1, 2024 (1) The rate of return on common equity for each Utility Registrant includes a 50-basis-point incentive adder for being a member of an RTO. (2) All rates are effective June 1, 2024 - May 31, 2025, subject to review by interested parties pursuant to protocols of each tariff.

26 Reconciliation of Non-GAAP Measures

27 Credit Metric GAAP to Non-GAAP Reconciliations(1) GAAP Operating Income + Depreciation & Amortization = EBITDA - Cash Paid for Interest +/- Cash Taxes +/- Other S&P FFO Adjustments = FFO (a) Long-Term Debt + Short-Term Debt + Underfunded Pension (after-tax) + Underfunded OPEB (after-tax) + Operating Lease Imputed Debt - Cash on Balance Sheet +/- Other S&P Debt Adjustments = Adjusted Debt (b) S&P FFO Calculation(2) S&P Adjusted Debt Calculation(2) Moody’s CFO (Pre-WC)/Debt (3) = CFO (Pre-WC) (c) Adjusted Debt (d) Moody’s CFO (Pre-WC) Calculation(3) Cash Flow From Operations +/- Working Capital Adjustment + Energy Efficiency Spend +/- Carbon Mitigation Credits +/- Other Moody’s CFO Adjustments = CFO (Pre-Working Capital) (c) Long-Term Debt + Short-Term Debt + Underfunded Pension (pre-tax) + Operating Lease Imputed Debt +/- Other Moody’s Debt Adjustments = Adjusted Debt (d) S&P FFO/Debt (2) = FFO (a) Adjusted Debt (b) Moody’s Adjusted Debt Calculation(3) (1) Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available; therefore, management is unable to reconcile these measures. (2) Calculated using S&P Methodology. (3) Calculated using Moody’s Methodology.

28 Projected Non-GAAP Operating Earnings Adjustments • Exelon’s projected 2025 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: – Costs related to ComEd’s regulatory matters; – Costs related to a change in ComEd’s FERC audit liability; and – Costs related to a cost management charge.

29 Q1 QTD GAAP EPS Reconciliation Three Months Ended March 31, 2025 ComEd PECO BGE PHI Other Exelon 2025 GAAP earnings (loss) per share $0.30 $0.26 $0.26 $0.19 ($0.11) $0.90 Regulatory matters 0.02 - - - - 0.02 2025 Adjusted (non-GAAP) operating earnings (loss) per share $0.32 $0.26 $0.26 $0.19 ($0.11) $0.92 Three Months Ended March 31, 2024 ComEd PECO BGE PHI Other Exelon 2024 GAAP Earnings (loss) per share $0.19 $0.15 $0.26 $0.17 ($0.11) $0.66 Change in FERC audit liability 0.03 - - - - 0.03 2024 Adjusted (non-GAAP) Operating Earnings (loss) per share $0.22 $0.15 $0.26 $0.17 ($0.11) $0.68 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS*. Amounts may not sum due to rounding.

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