November 4, 2025 Earnings Conference Call Third 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 Corporation’s (Exelon) and Commonwealth Edison Company’s (ComEd) 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, ComEd, 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). 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 $0.86 per share in Q3 2025 vs. $0.70 per share in Q3 2024 ▪ Adjusted Operating Earnings* of $0.86 per share in Q3 2025 vs. $0.71 per share in Q3 2024 ▪ Reaffirm 2025 EPS* of $2.64 - $2.74 per share(1) ▪ Exelon utilities now rank 1st, 2nd, 4th, and 7th among the most reliable utilities in the country ▪ ACE and DPL DE Gas rate cases remain on track; Pepco MD filed a distribution rate case ▪ Large load pipeline increasing to 19+ GW(2), with growing upside, while solutions to protect all customers, such as Transmission Security Agreements, remain in focus ▪ Advocating for resource adequacy solutions that ensure reliable transmission and cost- effective supply while meeting growing demand and state policy goals ▪ 7.4% rate base growth resulting from $38.0B of capital investment, and $10-15B of potential transmission opportunity beyond the plan ▪ Nearly half of equity needs through 2028 priced for issuance ▪ Reaffirming 2024-2028 EPS* CAGR of 5-7%(3) with expectation to be at midpoint or better (1) 2025 Adjusted Operating Earnings* guidance based on expected average outstanding shares of 1,013M. (2) See Appendix slide 13 for additional detail. (3) Based off the midpoint of Exelon’s 2024 Adjusted Operating Earnings* guidance range of $2.40 - $2.50 as disclosed at Q4 2023 Earnings Call in February 2024.
5 Q3 2025 QTD Adjusted Operating Earnings* Waterfall Note: Amounts may not sum due to rounding (1) Due to deferral of extraordinary February and June storm costs. (2) Lower income taxes driven by tax repairs deduction, some of which is timing. (3) 2025 Adjusted Operating Earnings* guidance based on expected average outstanding shares of 1,013M. $0.36 $0.28 $0.13 $0.12 ($0.09) $0.04 Q3 2024 $0.01 ComEd PECO $0.04 BGE $0.01 PHI ($0.03) Corp $0.08 $0.25 $0.29 $0.37 ($0.12) Q3 2025 $0.71 $0.86 BGE PECO PHI ComEd Corp ($0.01) Interest Expense ($0.02) Other $0.01 Distribution and Transmission Rates $0.01 Return on Regulatory Assets $0.01 AFUDC ($0.02) Timing of Distribution Earnings $0.08 Distribution Rates $0.05 Storm Costs(1) $0.02 Income Taxes(2) ($0.02) Depreciation $0.01 Distribution Rates $0.01 Storm Costs $0.01 Credit Loss Expense $0.01 Other $0.04 Distribution and Transmission Rates ($0.01) Interest Expense ($0.02) Other Reaffirming 2025 Adjusted Operating Earnings* of $2.64 - $2.74 per share(3)
Jul Aug Sept Oct Nov Dec Jan Feb Mar Apr May Jun Jul Revenue Requirement Increase Requested ROE / Equity Ratio Expected Order Date $37.4M 10.65% / 50.50% Q1 2026 $108.9M 10.70% / 50.24% Dec 2025 $133.2M 10.50% / 51.25% Aug 2026 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 22 for further detail on pertinent rate case data and information. DPL DE Gas Filed base distribution rate cases account for ~9% of Exelon’s consolidated rate base ACE Electric IT RT EH 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 – Revised Briefs filed on 9/5/2025 – 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 – Reply briefs filed on 10/14/2025 – Proposed Order expected 11/4/2025 FOIT RT EH Pepco MD Electric CF
Strong Balance Sheet Provides Strategic and Financial Flexibility Credit Metric Outlook %*(2,3) Credit Ratings / Outlooks(6) ExCorp ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 (Stable) A1 (Stable) Aa3 (Negative) A3 (Stable) A2 (Stable) A2 (Positive) 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) Exelon established a $2.5B ATM program on May 2, 2025, effective through May 2, 2028. (6) Current senior unsecured ratings for Exelon and BGE and current senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco. 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 ▪ 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 100% of 2025’s debt financing needs, mitigating remaining exposure to interest rate volatility for this year ▪ 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 nearly half of our equity needs through 2028, including 100% of 2025’s and ~95% of 2026’s annualized equity needs via ATM(5)
8 2025 Business Priorities and Commitments Focused on continued execution of operational, regulatory, and financial priorities to advance the interests 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 1,013M.
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 Pipeline of 19+ GW(2) of large load, with significant further growth expected 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) See Appendix slide 13 for additional detail. (3) 2024 supplier spend based on Exelon’s 2024 Sustainability Report. (4) Based off the midpoint of Exelon’s 2024 Adjusted Operating Earnings* guidance range of $2.40 - $2.50 as disclosed at Q4 2023 Earnings Call in February 2024. (5) 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(4), which combined with ~60% dividend payout ratio(5) results in an attractive risk-adjusted total annual return of 9-11% Exelon utilities rank 1st, 2nd, 4th, and 7th among the nation's most reliable utilities in 2024 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(3) 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
Industry Trends Drive 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(2) ▪ 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, with competitive projects offering further upside, 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. (2) As an example, the Illinois Clean and Reliable Grid Affordability Act (CRGA) – SB 25 allows the Commission discretion to ask utilities and other parties to identify transmission projects necessary to facilitate the goals of the Renewable Energy Access Plan (REAP). The bill is pending Governor signature as of November 4, 2025.
Exelon is Well-Positioned for Transmission Solutions 12 Size and scale, prime geographic footprint, and a robust capital plan focused on grid modernization and resilience (1) Estimated transmission capital as of historical Q4 rollforwards. Rate base estimates as disclosed at Q4 2024 Earnings Call in February 2025. (2) Reflects transmission miles as of December 31, 2024 as reported in the Form 10-K. …support Exelon’s competitive edge for transmission opportunities ➢ 1 of 4 U.S. 765kV transmission operators with decades of experience ➢ 11,189 Transmission Lines including 3,597 circuit miles of extra high voltage lines (>300kV)(2) ➢ Tri-County Line: competitively awarded $1B+, 59-mile upgrade ➢ Indian River: completed ~2 years ahead of Reliability-Must-Run schedule, saving customers ~$100M ➢ MISO LRTP Tranche 2.1: working with MISO on a potential $1B+ project to support MISO’s long-term energy supply plan ➢ Fall 2025: Independent and joint bids submitted in PJM’s 2025 RTEP Window #1 ➢ Late 2025: Initial Staff Recommendations for PJM’s 2025 RTEP Window #1 ➢ Q1 2026: PJM’s 2025 RTEP Window #1 – Board Approval ➢ 2026+: Ongoing annual planning processes10.5 11.5 12.3 12.6 13.2 14.9 18.4 20% 2022A 21% 2023A 20% 2024A 20% 2025E 19% 2026E 20% 2027E 23% 2028E +9.9% Transmission CapEx ($M)(1) Transmission Rate Base ($B)(1) 6,350 6,675 22% 2022 - 2025E 21% 2023 - 2026E 28% 2024 - 2027E 33% 2025 - 2028E 9,675 12,550 %T of CapEx/Rate Base Long-Term Transmission Planning Projects Other Transmission Continued investment and an expansive footprint… PJM Transmission Development Outlook Recent Successes
Projected Data Center Load Growth in Exelon’s Footprint 13 Exelon is a Key Partner in Driving Economic Development 0 100 200 300 400 500 600 700 ‘15 ‘22 ‘23 ‘24 ‘25 ~27% CAGR(1) Data Center Load in Northern IL(1) M W (1) Represents historical on-peak hourly demand for in-service data centers in the ComEd service territory. 2025 actuals YTD as of 9/30/2025; ~27% CAGR is based on YTD Sep ’25 vs. YTD Sep ’22. (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 Q3 2025. Phase 1 represents projects where initial design is nearly complete and deposits are collected, and have TSAs signed with customers when presented for signature; phase 2 projects are undergoing more definitive engineering and cost estimates and 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. A proven leader in the data center market... …with an 18+ GW(2) and growing data center pipeline YTD(1) 1 6 11 16 5 15 25 30 35 40 45 50 0 Q4 ’22 Q4 ’23 Q3 ’24 Q4 ’24 Q3 ’25 ~20 11+ 10+ ~6 Future Potential Additions 18+ 47+Phase 3 Phase 2 Phase 1 Awaiting Cluster Studies (2026+) Active Midatlantic Cluster Study Active ComEd Cluster Study Awaiting Signed TSAs Large Load Adjustments submitted in 2024 were fully approved by PJM, and YTD demand continues to support confidence in outlook, exceeding estimate by 16% ~9% CAGR G W Expected late 2025 / early 2026 Studies expected to conclude in 2026 Studies expected to start in 2026 ComEd and PECO recognized as top utilities in economic development in the U.S. by Site Selection Magazine Prioritizing large loads while protecting existing customers through the formalization and signing of Transmission Security Agreements (TSA)
14 Rapid, large scale load growth creates significant economic development opportunity in our communities and accelerates interest in creative solutions to the energy transition June 27, 2025 IL: Elk Grove Substation Expansion June 9, 2025 PA: Northpoint Bucks County Data Center September 13, 2024 IL: CyrusOne Aurora Data Center June 13, 2024 IL: Compass Datacenters September 24, 2025 MD: BGE, Ford, & Sunrun Vehicle-to-Grid Pilot September 30, 2025 IL: PsiQuantum Utility- Scale Quantum Computer February 27, 2025 IL: Edged Data Center Campus October 11, 2025 IL: GrayslakeT5 Data Center Campus May 13, 2025 IL: CyrusOne Wood Dale Topping Out Ceremony July 15, 2025 IL: Itasca Substation Upgrades July 31, 2025 IL: Prologis Community Solar Launch September 9, 2025 IL: Elk Grove Stream Data Center Campus The Power of Impact: Growth and Progress in Our Communities
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 15 StatesFederal Agencies Regional Transmission Operator (1) Revised CIR Transfer Proposal – FERC docket ER26-403 (2) Anticipated conclusion of legislative session, or, for Maryland, anticipated start of next legislative session. (3) MD PSC Dispatchable Generation and Large Capacity Energy Resource Solicitation – PC74 (4) Illinois Clean and Reliable Grid Affordability Act (CRGA) – SB 25, which is pending Governor signature as of 11/4/25 (5) PA Power Act – HB 1272 (4/21/25) & SB 897 (6/30/25) (6) Governor Murphy signed A5267 & S4530 (8/22/25) and A5563 (9/24/25) into legislation; S4293 conditionally vetoed (10/20/25) ▪ MD (1/14/2026)(2): MD PSC initiated a 3 GW generation 30-day RFP on 10/1/25 to solicit competitive third-party bids(3); an active 2026 legislative session is expected, and will be informed in part by the outcome of the RFP ▪ IL (Veto Session 10/30/25)(2): Energy omnibus bill(4) supports battery storage, energy efficiency, resource planning, and transmission to advance energy transition ▪ PA (11/30/26)(2): Draft bills(5) advance energy security, allowing for regulated generation in conjunction with procurement via long-term contracts ▪ NJ (1/13/26)(2,6): Approved bills expanding community solar targets, initiating a transmission-scale energy storage incentive program, and supporting summer customer affordability; bill for data center energy usage filings returned with proposed amendments ▪ DE: DPL working with DE PSC & DPA to implement large load (25+ GW) tariff to ensure fair infrastructure costs Adopt policies that promote energy security, economic development, and reliable and resilient energy delivery Shape large load policies to protect customers, promote economic growth, and support reliability Transmission Policy ▪ Enable more proactive and flexible transmission planning to support timely interconnection of load and generation ▪ Retain incentives policy that benefits customers and supports needed transmission development Large Load Protections ▪ Continue to develop policies, including Transmission Security Agreements, that protect customers and demonstrate responsible bottom-up policy development to facilitate AI Accountability Gaps in Generation Planning ▪ Continue working with federal and state regulators to jumpstart supply response in PJM ▪ Address wholesale supply costs, which have increased 60% year over year Facilitate supply in line with the pace of demand and solve near-term affordability challenges Shorter-Term Solutions ▪ Continue to constructively shape PJM Critical Issue Fast Path (CIFP) reforms supporting large load additions, including demand response, load forecasting, and generator interconnection ▪ Support extending capacity price collar with end date to drive more permanent solutions ▪ Support PJM’s pending reforms for Capacity Interconnection Rights (CIR) transfer rules(1) to timely interconnect new generation at brownfield sites ▪ Finalize long-term transmission planning procedures Mid-Term Solutions ▪ Extend and refine temporary prioritized queue process for select shovel-ready generation resources (e.g., state prioritized resources) ▪ Move to seasonal capacity market to refine price signals Longer-Term Solutions ▪ State-directed planning and procurement of generation resources to better align economic and energy policy goals, with capacity market providing residual support
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 Earnings* 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 Earnings* 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. On September 30, 2025, FERC approved BGE to utilize CWIP treatment for the Tri-County Line project (effective 10/1/25). 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 16 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.
17 Q3 2025 YTD Adjusted Operating Earnings* Waterfall Note: Amounts may not sum due to rounding (1) Lower income taxes driven by tax repairs deduction, some of which is timing. $0.28 ($0.32) ($0.40) $0.35 $0.36 $0.61 $0.86 Q3 2024 $0.06 ComEd PECO $0.04 BGE $0.01 PHI ($0.08) Corp $0.39 $0.64 $0.62 $0.92 Q3 2025 $1.86 $2.17 BGE PECO PHI ComEd Corp ($0.04) Customer Relief Fund ($0.02) Interest Expense ($0.02) Other $0.03 Distribution and Transmission Rates $0.02 Return on Regulatory Assets $0.01 Timing of Distribution Earnings $0.01 AFUDC ($0.02) Transmission Peak Load $0.01 Other $0.24 Distribution Rates $0.04 Income Taxes(1) $0.03 Weather $0.02 Storm Costs ($0.02) Depreciation ($0.01) Interest Expense ($0.02) Other $0.05 Distribution and Transmission Rates $0.01 Storm Costs ($0.01) Interest Expense ($0.01) Other $0.11 Distribution and Transmission Rates ($0.03) Interest Expense ($0.02) Pepco MYP Reconciliations ($0.01) AFUDC ($0.01) Depreciation ($0.03) Other
2025 Financing Plan(1) 2025 balanced capital plan completed in Q3, supporting continued strong investment grade credit ratings Entity Instrument Issuance ($M) Maturity ($M) Issued ($M)(2) Remaining ($M) FMB $725 - $725 - FMB $275 - $275 - FMB $250 ($150) $250 - FMB / Tax-Exempts $203 ($78) $203 - FMB $1,050 ($350) $1,050 - Senior Notes $650 - $650 - Senior Notes / Other(3) $2,000 ($807) $2,000(3) - Equity(4) $700 - $700(4) - 18 Note: As of September 30, 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 funded $75M on September 17, 2025 and ACE will fund $150M in November 2025. (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. $525M of the $700M was issued under forward contracts to be settled by December 15, 2025.
Exelon Debt Maturity Profile(1,2) Debt Balances (as of 9/30/25)(1,2) ($B) Short-Term Debt Long-Term Debt Total Debt BGE $0.0 $6.0 $6.0 ComEd $0.0 $13.0 $13.0 PECO $0.0 $6.9 $6.9 PHI $0.2 $9.6 $9.8 Corp $0.9(3) $13.3 $14.2 Exelon $1.1 $48.8 $49.9 500 750 650 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 1,500 850 360 997 303 600 1,178 625 2,323 1,645 1,575 1,225 1,200 1,650 2,400 1,650 1,325 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 Q3 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 9/30/2025 EXC Regulated ExCorp 19
20 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 15.6% 20.1% Exelon Consolidated Cash Tax Rate(2) 9.1% 13.4% (1) Reflects full year impact to a +50bp increase on Corporate debt net of pre-issuance hedges as of September 30, 2025. Through September 30, 2025, Corporate entered into $0.7B of pre-issuance hedges through interest rate swaps. (2) Includes the impact of CAMT.
21 Rate Case Details
22 Exelon Distribution Rate Case 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: Unless otherwise noted, based on schedules of Delaware Public Service Commission (DE PSC), New Jersey Board of Public Utilities (NJBPU), and Maryland Public Service Commission (MD PSC), that are subject to change. (1) Prehearing conference scheduled on November 18, 2025; procedural schedule expected to be set at the time of conference (2) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings. (3) Requested revenue requirement excludes the transfer of $8.0M 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 4/20/25, subject to refund. (4) 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. Jul Aug Sept Oct Nov Dec Jan Feb Mar Apr May Jun Jul Revenue Requirement Increase Requested ROE / Equity Ratio Expected Order Date $37.4M(2,3) 10.65% / 50.50% Q1 2026 $108.9M(2,4) 10.70% / 50.24% Dec 2025 $133.2M(2) 10.50% / 51.25% Aug 2026 DPL DE Gas ACE Electric IT RT EH FO FOIT RT EH Pepco MD Electric(1) CF
23 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 (WNA) rider, effective from October to May designed to adjust for differences between normalized, historical and actual weather ▪ If approved, the WNA rider will provide customers with more bill predictability, while allowing DPL the opportunity to earn its authorized distribution revenues Test Period 12 months actual Test Year April 1, 2024 – March 31, 2025 Proposed Common Equity Ratio 50.51% Proposed Rate of Return ROE: 10.65%: ROR: 7.55% Proposed Rate Base (Adjusted) $729M Requested Revenue Requirement Increase $37.4M(1) Residential Total Bill % Increase 21.0% 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 11/10/2025 - 11/17/2025Evidentiary hearings Reply briefs Commission order expected(2) Q1 2026 Initial briefs (1) Requested revenue requirement excludes the transfer of $8.0M 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 4/20/25, 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.
24 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 (NJBPU) 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) Residential Total Bill % Increase 8.1% Detailed Rate Case Schedule(3) Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Evidentiary hearings Initial briefs 11/21/2024 Reply briefs Dec 2025 Intervenor testimony Commission order expected(2) Rebuttal testimony Filed rate case (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) There is no statutory deadline by which the Board of Public Utilities needs to rule. (3) ACE’s procedural schedule was suspended on August 4, 2025; there is no statutory deadline by which the Board of Public Utilit ies needs to rule.
25 Pepco MD Distribution Rate Case Filing Rate Case Filing Details Notes Case No. 9820 ▪ October 14, 2025, Pepco filed with the Maryland Public Service Commission (MD PSC) seeking an increase in base distribution rates ▪ Pepco’s Fully Forecasted Test Year (FFTY) (1) rate increase supports: ▪ Customer Value: Expanding bill mitigation options and energy assistance to address affordability amid rising costs. ▪ Reliability: Upgrading infrastructure to meet growing demand and ensure customers continue receiving dependable service. ▪ Clean Energy Goals: Supporting Maryland’s transition to clean energy, fostering job creation, and driving economic development. ▪ Customer Benefits: Implementing investments and programs designed to help customers effectively manage energy costs. ▪ The filing seeks recovery for plant additions, increase in cost of capital, and increase in operating expenses Test Period 12 months forecast Test Year January 1, 2026 – December 31, 2026 Proposed Common Equity Ratio 51.25% Proposed Rate of Return ROE: 10.50%: ROR: 7.87% Proposed Rate Base (Adjusted) $3,037M Requested Revenue Requirement Increase $133.2M Residential Total Bill % Increase 6.7% Detailed Rate Case Schedule(2) Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug 10/14/2025Filed rate case Intervenor testimony Rebuttal testimony Evidentiary hearings Initial briefs Reply briefs Commission order expected (1) Traditional Test Year Compliance Filing (TTYCF) filed with the FFTY in compliance with Order No. 91181 in Case No. 9702. TTYCF results in higher adjusted revenue requirement ($141.7M) primarily due to inclusion of ratemaking adjustments designed to align revenue requirement with rate effective period. (2) Prehearing conference scheduled for November 18, 2025; procedural schedule expected to be set at the time of conference.
26 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 MD PSC 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 MD PSC 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 MD PSC 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 MD PSC, 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 MD PSC 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.
27 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 MD PSC 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 MD PSC 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.
28 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 $127M 11.50% 54.56% Jun 1, 2025 PECO $22M 10.35% 54.27% Jun 1, 2025 BGE $35M 10.50% 53.08% Jun 1, 2025 Pepco $51M 10.50% 50.30% Jun 1, 2025 DPL $23M 10.50% 50.48% Jun 1, 2025 ACE ($57M) 10.50% 49.99% Jun 1, 2025 (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, 2025 - May 31, 2026, subject to review by interested parties pursuant to protocols of each tariff.
29 Reconciliation of Non-GAAP Measures
30 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; – Income tax-related adjustments; – Costs related to a cost management charge; and – Other items not directly related to the ongoing operations of the business.
31 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.
32 Q3 QTD GAAP EPS Reconciliation Three Months Ended September 30, 2025 ComEd PECO BGE PHI Other Exelon 2025 GAAP earnings (loss) per share $0.37 $0.25 $0.08 $0.29 ($0.12) $0.86 2025 Adjusted (non-GAAP) operating earnings* (loss) per share $0.37 $0.25 $0.08 $0.29 ($0.12) $0.86 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. Three Months Ended September 30, 2024 ComEd PECO BGE PHI Other Exelon 2024 GAAP earnings (loss) per share $0.36 $0.12 $0.04 $0.28 ($0.09) $0.70 2024 Adjusted (non-GAAP) operating earnings* (loss) per share $0.36 $0.12 $0.04 $0.28 ($0.09) $0.71
33 Q3 YTD GAAP EPS Reconciliation Nine Months Ended September 30, 2025 ComEd PECO BGE PHI Other Exelon 2025 GAAP earnings (loss) per share $0.89 $0.64 $0.39 $0.62 ($0.40) $2.15 Regulatory matters 0.02 - - - - 0.02 2025 Adjusted (non-GAAP) operating earnings* (loss) per share $0.92 $0.64 $0.39 $0.62 ($0.40) $2.17 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. Nine Months Ended September 30, 2024 ComEd PECO BGE PHI Other Exelon 2024 GAAP earnings (loss) per share $0.82 $0.36 $0.35 $0.60 ($0.32) $1.81 Change in FERC audit liability 0.04 - - - - 0.04 Cost management charge - - - - - 0.01 2024 Adjusted (non-GAAP) operating earnings* (loss) per share $0.86 $0.36 $0.35 $0.61 ($0.32) $1.86
Thank you Please direct all questions to the Exelon Investor Relations team: InvestorRelations@ExelonCorp.com 779-231-0017
